Rice Midstream Partners LP (Form: 10-K, Received: 02/15/2018 16:27:13)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2017

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from_______ to_______

Commission File Number: 001-36789

Rice Midstream Partners LP

(Exact name of registrant as specified in its charter)



Delaware		47-1557755
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
625 Liberty Avenue, Suite 1700 Pittsburgh, Pennsylvania		15222
(Address of principal executive offices)		(Zip code)

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

Securities registered pursuant to Section 12(b) of the Act:
Title of each class		Name of each exchange on which registered
Common Units Representing Limited Partner Interests		New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. þ Yes ¨ No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ¨ Yes þ No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þ Yes ¨ No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a small reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ		Accelerated filer ¨
Non-accelerated filer ¨		Smaller reporting company ¨
(Do not check if a smaller reporting company)		Emerging growth company ¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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

The aggregate market value of the common units held by non-affiliates of the registrant as of June 30, 2017 : $1.5 billion

At January 31, 2018 , there were 102,303,108 units (consisting of 73,549,485 common units and 28,753,623 subordinated units) outstanding.

Documents Incorporated by Reference

None

RICE MIDSTREAM PARTNERS LP

ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS



	Page
Cautionary Statements	4
Commonly Used Defined Terms	5

PART I
Item 1. Business	6
Item 1A. Risk Factors	16
Item 1B. Unresolved Staff Comments	40
Item 2. Properties	40
Item 3. Legal Proceedings	40
Item 4. Mine Safety Disclosures	41

PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	42
Item 6. Selected Financial Data	43
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	44
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	55
Item 8. Financial Statements and Supplementary Data	57
Item 9. Changes in Disagreements with Accountants on Accounting and Finance Disclosure	83
Item 9A. Controls and Procedures	83
Item 9B. Other Information	83

PART III
Item 10. Directors, Executive Officers and Corporate Governance	84
Item 11. Executive Compensation	89
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	95
Item 13. Certain Relationships and Related Transactions and Director Independence	98
Item 14. Principal Accountant Fees and Services	105

PART IV
Item 15. Exhibits and Financial Statement Schedules	107
Signatures	110
Glossary of Oil and Natural Gas Terms	111

Cautionary Statements

Disclosures in this Annual Report on Form 10-K contain certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. Statements that do not relate strictly to historical or current facts are forward-looking and usually identified by the use of words such as “anticipate,” “estimate,” “could,” “would,” “will,” “may,” “forecast,” “approximate,” “expect,” “project,” “intend,” “plan,” “believe” and other words of similar meaning in connection with any discussion of future operating or financial matters. Without limiting the generality of the foregoing, forward-looking statements contained in this Annual Report on Form 10-K include the matters discussed in the sections captioned Item 1, “Business” and “Outlook” in Item 7, “Management's Discussion and Analysis of Financial Condition and Results of Operations,” and the expectations of plans, strategies, objectives, and growth and anticipated financial and operational performance of us and its subsidiaries, including guidance regarding our gathering and water services revenue and volume growth; infrastructure programs (including the timing, cost, capacity and sources of funding with respect to gathering and water services expansion projects); natural gas production growth in our operating areas for EQT and third parties; the timing of EQT’s announcement of a decision for addressing its sum-of-the-parts discount; the amount and timing of distributions, including expected increases; the amounts and timing of projected operating and capital expenditures; the impact of commodity prices on our businesses; liquidity and financing requirements, including sources and availability; the effects of government regulation and litigation; and tax position. The forward-looking statements included in this Annual Report on Form 10-K involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. We have based these forward-looking statements on current expectations and assumptions about future events. While we consider these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, many of which are difficult to predict and are beyond our control. The risks and uncertainties that may affect the operations, performance and results of our businesses and forward-looking statements include, but are not limited to, those set forth under “Item 1A. Risk Factors” and elsewhere in this Annual Report on Form 10-K.

Any forward-looking statement speaks only as of the date on which such statement is made and we do not intend to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.

In reviewing any agreements incorporated by reference in or filed with this Annual Report on Form 10-K, please remember that such agreements are included to provide information regarding the terms of such agreements and are not intended to provide any other factual or disclosure information about us. The agreements may contain representations and warranties by us, which should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to such agreements should those statements prove to be inaccurate. The representations and warranties were made only as of the date of the relevant agreement or such other date or dates as may be specified in such agreement and are subject to more recent developments. Accordingly, these representations and warranties alone may not describe the actual state of affairs of us or our affiliates as of the date they were made or at any other time.

Commonly Used Defined Terms

As used in the Annual Report on Form 10-K, unless the context indicates or otherwise requires, the following terms have the following meanings:


•	“Combined Year” refers to the combined periods from January 1, 2017 to November 12, 2017 and from November 13, 2017 to December 31, 2017.


•	“EQT” refers to EQT Corporation, which effective November 13, 2017 indirectly owns the general partner interest, a limited partner interest and all of the incentive distribution rights in the Partnership, and its consolidated subsidiaries;


•	“GP Holdings” refers to Rice Midstream GP Holdings LP, a wholly-owned subsidiary of EQT;


•	“our general partner” or “Midstream Management” refers to Rice Midstream Management LLC, a wholly-owned subsidiary of EQT;


•	“Rice Energy” refers to Rice Energy Inc., which indirectly owned the Partnership for the periods prior to November 13, 2017, and its consolidated subsidiaries;


•	“RMP,” “Partnership,” “we,” “our,” “us” or like terms refers to Rice Midstream Partners LP and its consolidated subsidiaries;


•	“Vantage Midstream Asset Acquisition” refers to the Partnership’s acquisition from Rice Energy of the Vantage Midstream Entities;


•	“Vantage Midstream Entities” refers collectively to Vantage Energy II Access, LLC and Vista Gathering, LLC, each of which is a wholly-owned subsidiary of the Partnership;


•	“Appalachian Basin” refers to the area of the United States composed of those portions of West Virginia, Pennsylvania, Ohio, Maryland, Kentucky and Virginia that lie in the Appalachian Mountains; and


•	“Disclosure Document” means EQT’s 2018 Proxy Statement or amendments to its Annual Report on Form 10-K for the year ended December 31, 2017, as applicable, in each case as filed with the Securities and Exchange Commission (SEC).

PART I

Item 1. Business

Overview

We are a growth-oriented limited partnership formed by Rice Energy to own, operate, develop and acquire midstream assets in the Appalachian Basin. We operate in two business segments, which are managed separately due to their distinct operational differences: (i) gathering and compression and (ii) water services. Our natural gas gathering assets consist of natural gas gathering systems and associated compression that service EQT and other third-party producers in the dry gas core of the Marcellus Shale in southwestern Pennsylvania. Our water services assets consist of water pipelines, impoundment facilities, pumping stations, take point facilities and measurement facilities, which are used to support well completion activities and to collect and recycle or dispose of flowback and produced water for EQT and other third-party producers in Washington and Greene Counties, Pennsylvania and Belmont County, Ohio. We provide our services under long-term, fee-based contracts, primarily to EQT and its affiliates. 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.

On November 13, 2017 (the Merger Date), EQT and Rice Energy consummated the transactions contemplated by the Agreement and Plan of Merger, dated as of June 19, 2017 (as amended, the Merger Agreement), by and among EQT, Rice Energy and a wholly-owned subsidiary of EQT (Merger Sub). Pursuant to the Merger Agreement, Merger Sub merged with and into Rice Energy, with Rice Energy continuing as the surviving entity and an indirect, wholly-owned subsidiary of EQT. Immediately thereafter Rice Energy merged with and into another indirect, wholly-owned subsidiary of EQT (together, the Mergers).

Prior to the completion of the Mergers, Rice Energy was the indirect parent of our general partner and an indirect limited partner of us. Immediately following the completion of the Mergers, EQT became the indirect parent of our general partner and an indirect limited partner of us, acquiring beneficial ownership of 3,623 common units representing limited partner interests, 28,753,623 subordinated units representing limited partner interests and all of our incentive distribution rights (IDRs), which entitle EQT to receive 50% of all incremental cash distributed in a quarter after $0.2813 has been distributed in respect of each common unit of RMP for that quarter. The subordinated units converted into common units on a one-for-one basis on February 15, 2018.

Our Assets

Gathering and Compression Segment

Our gathering and compression assets are concentrated in the dry gas core of the Marcellus Shale and, as of December 31, 2017 , consisted of a high-pressure dry gas gathering system and associated compression in Washington and Greene Counties, Pennsylvania, with connections to the Dominion Transmission, Columbia Gas Transmission, Texas Eastern Transmission, Equitrans Transmission and National Fuel Gas Supply interstate pipelines. The dry gas core of the Marcellus Shale in southwestern Pennsylvania is characterized by a combination of low development costs, consistently high production volumes and access to multiple takeaway pipelines. For the three months ended December 31, 2017 , our average daily throughput was 1,539 BBtu/d. As of December 31, 2017 , our gathering assets consisted of 178 miles of pipeline with gathering capacity of 5.1 TBtu/d and compression capacity of approximately 85,000 horsepower.

We contract with EQT and other producers to gather and compress natural gas from wells and well pads located in our dedicated areas and/or near our gathering systems. The natural gas we gather and compress generally requires no processing or treating prior to delivery into interstate pipelines.

We generate all of our gathering and compression revenues pursuant to long-term, fixed price per unit contracts. We generate revenue primarily by charging a fixed price per unit for volumes of natural gas that we gather and compress through our systems. Our assets are sized to accommodate the projected future production growth of EQT, as well as to allow us to pursue volumes from additional third parties. We have secured dedications from certain EQT affiliates under various fixed price per unit gathering and compression agreements covering (i) approximately 246,000 gross acres of EQT’s acreage position as of December 31, 2017 in Washington and Greene Counties, Pennsylvania, and (ii) subject to certain exceptions and limitations pursuant to the gathering and compression agreements, any future acreage certain affiliates of EQT acquire within these counties.

Following the completion of the Mergers, EQT became our largest customer, representing substantially all of our gathering and compression volumes for the year ended December 31, 2017 when considering the combined volumes of EQT and Rice Energy.

Water Services Segment

Our water services assets consist of water pipelines, impoundment facilities, pumping stations, take point facilities and measurement facilities, which are used to support well completion activities and to collect and recycle or dispose of flowback and produced water for EQT and other third parties in Washington and Greene Counties, Pennsylvania, and Belmont County, Ohio. We have the exclusive right to provide certain fluid handling services to EQT until December 22, 2029, and from month to month thereafter. The fluid handling services include the exclusive right to provide fresh water for well completions operations and to collect and recycle or dispose of flowback and produced water for EQT within certain areas of dedication in defined service areas in Washington and Greene Counties, Pennsylvania and Belmont County, Ohio. We also provide water services to third parties under fee-based contracts to support well completion activities. As of December 31, 2017 , our Pennsylvania assets provided access to 29.4 MMgal/d of fresh water from the Monongahela River and several other regional water sources, while our Ohio assets provided access to 14.0 MMgal/d of fresh water from the Ohio River and several other regional water sources, both for distribution to EQT and third parties.

Following the completion of the Mergers, EQT became our largest customer, representing approximately 91% of our water services volumes for the year ended December 31, 2017 when considering the combined volumes of EQT and Rice Energy.

Please see Note 10 to the Consolidated Financial Statements included in this Annual Report for additional information about our segments.

2018 Capital Budget

In 2018, we plan to invest $260 million on organic projects, of which $215 million is expected to be used for our continued build-out of our Pennsylvania gas gathering systems and $45 million is expected to be used for our water services infrastructure.

Our Customers

EQT (inclusive of the results of Rice Energy prior to the Mergers) represented substantially all of our gathering and compression revenues and 96% of our water revenues for the year ended December 31, 2017 .

Our Relationship with EQT

EQT is an integrated energy company, with an emphasis on natural gas production, gathering and transmission. EQT conducts its business through five business segments: EQT Production, EQM Gathering, EQM Transmission, RMP Gathering and RMP Water. EQT Production holds 21.4 Tcfe of proved natural gas, NGLs and crude oil reserves across approximately 4.0 million gross acres, including approximately 1.1 million gross acres in the Marcellus play, many of which have associated deep Utica and/or Upper Devonian drilling rights, and approximately 0.1 million gross acres in the Ohio Utica play as of December 31, 2017. EQM Gathering and EQM Transmission provide gathering, transmission and storage services for EQT's produced gas, as well as for independent third parties across the Appalachian Basin through EQT Midstream Partners, LP (EQM).

Following the completion of the Mergers, EQT became the indirect parent of our general partner, which owned the non-economic general partner interest in us, and acquired beneficial ownership of a 28.1% limited partner interest in us and all of our IDRs. In addition, as of December 31, 2017, EQT indirectly held a 90.1% limited partner interest and 100% of the non-economic general partner interest in EQT GP Holdings, LP (EQGP), which owned a 1.8% general partner interest in EQM, all of the IDRs in EQM and a 26.6% limited partner interest in EQM.

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

Title to Properties and Rights-of-Way

Our real property is classified into two categories: (i) parcels that we own in fee and (ii) parcels in which our interest derives from leases, easements, right-of-ways, permits or licenses from landowners or government authorities, permitting the use of such land for our operations. Portions of the land on which our pipelines and major 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 major 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 these lands 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 of such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of its material leases, easements, rights-of-way, permits and licenses.

Some of the leases, easements, rights-of-way, permits and licenses that were transferred to us from Rice Energy required the consent of the grantor of such rights, which in certain instances is a governmental entity. Rice Energy obtained 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. With respect to any remaining consents, permits or authorizations that have not been obtained, we have determined these will not have a material adverse effect on the operation of our business should we fail to obtain such consents, permits or authorization in a reasonable time frame.

Seasonality

Demand for natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. These seasonal anomalies can increase demand for our services during the summer and winter months and decrease demand for our services during the spring and fall months.

Competition

Key competitors for new gathering systems include companies that own major natural gas pipelines, independent gas gatherers and integrated energy companies. Many of our competitors, including EQM, have capital resources and control supplies of natural gas greater than we do. Key competition for water services include natural gas producers that develop their own water distribution systems in lieu of employing our assets and other natural gas midstream companies. Our ability to attract volumes to the water services business depends on our ability to evaluate and select suitable projects and to consummate transactions in a highly competitive environment.

Regulation of Operations

Regulation of pipeline gathering services may affect certain aspects of our business and the market for our services. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily the Federal Energy Regulatory Commission (FERC). FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that EQT produces, as well as the revenues EQT receives for sales of its natural gas.

The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act (NGA) and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation, gathering, and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase EQT’s costs of getting gas to point of sale locations. State regulation of natural gas gathering facilities generally include various safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, states are currently pursuing regulatory programs intended to safely build pipeline infrastructure. For instance, the Pennsylvania Pipeline Infrastructure Task Force is currently developing policies and guidelines to assist in pipeline development to, among other goals, ensure pipeline safety and integrity during operation of the pipeline.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as our assets are determined to be intrastate transportation

facilities, such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, and we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis would not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that EQT produces, as well as the revenues EQT receives for sales of its natural gas.

Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas gatherers with which we compete.

FERC is authorized to impose civil penalties of up to approximately $1.2 million per violation, per day for violations of the NGA, the Natural Gas Policy Act (NGPA) or the rules, regulations, restrictions, conditions and orders promulgated under those statutes. This maximum penalty authority established by statute will continue to be adjusted periodically for inflation. The civil penalty provisions are applicable to entities that engage in the transportation and sale of natural gas for resale in interstate commerce.

The Energy Policy Act of 2005 (EPAct 2005) amended the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior as prescribed by FERC. In Order No. 670, the FERC promulgated rules implementing the anti-market manipulation provision of EPAct 2005. The rules make it unlawful 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, (1) 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 anti-market 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.

Gathering Pipeline Regulation

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by the FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests the FERC has used to establish whether a pipeline is a gathering pipeline not subject to FERC jurisdiction as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is often the subject of litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by the FERC, the courts, or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or the NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.

While our systems have not been regulated by FERC as a natural gas company under the NGA, we are required to report aggregate volumes of natural gas purchased or sold at wholesale to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. In addition, Congress may enact legislation or FERC may adopt regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to further regulation. Failure to comply with those regulations in the future could subject us to civil penalty liability.

State regulation of natural gas gathering facilities and intrastate transportation pipelines generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. Our natural gas gathering facilities are not subject to rate regulation or open access requirements in the states in which we operate. However, state regulators may require us to register as pipeline operators, pay assessment and registration fees, undergo inspections, and report annually on the miles of pipeline we operate. We cannot predict what new or different regulations federal and state regulatory agencies may adopt, or what effect subsequent regulation may have on our activities. Such regulations may have a material adverse effect on our financial condition, result of operations and cash flows.

Pipeline Safety Regulation

Some of our pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (PHMSA), pursuant to the Natural Gas Pipeline Safety Act of 1968 (NGPSA), and the Pipeline Safety Improvement Act of 2002 (PSIA), as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (2006 PIPES Act). The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transmission pipelines in high-consequence areas (HCAs).

The PHMSA has developed regulations that require pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in HCAs. The regulations require operators, including us, to:


•	perform ongoing assessments of pipeline integrity;


•	identify and characterize applicable threats to pipeline segments that could impact an HCA;


•	improve data collection, integration and analysis;


•	repair and remediate pipelines as necessary; and


•	implement preventive and mitigating actions.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Pipeline Safety Act) reauthorizes funding for federal pipeline safety programs, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. The 2011 Pipeline Safety Act, among other things, increases the maximum civil penalty for pipeline safety violations and 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 HCAs. PHMSA has the authority to impose civil penalties for pipeline safety violations up to a maximum of approximately $200,000 per day for each violation and approximately $2 million for a related series of violations. This maximum penalty authority established by statute will continue to be adjusted periodically to account for inflation. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as well as any implementation of PHMSA regulations thereunder or any issuance or reinterpretation of PHMSA guidance with respect thereto could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any of which could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position.

PHMSA regularly revises its pipeline safety regulations. For example, in March of 2015, PHMSA finalized new rules applicable to gas and hazardous liquid pipelines that, among other changes, impose new post-construction inspections, welding, gas component pressure testing requirements, as well as requirements for calculating pressure reductions for immediate repairs on liquid pipelines. Additionally, in April 2016, PHMSA proposed rules that would, if adopted, impose more stringent requirements for certain gas lines. Among other things, the proposed rulemaking would extend certain of PHMSA’s current regulatory safety programs for gas pipelines beyond HCAs to cover gas pipelines found in newly defined “moderate consequence areas” that contain as few as five dwellings within the potential impact area and would also require gas pipelines installed before 1970 that are currently exempted from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures (MAOP). Other new requirements proposed by PHMSA under the rulemaking would require pipeline operators to: report to PHMSA in the event of certain MAOP exceedances; strengthen PHMSA integrity management requirements; consider seismicity in evaluating threats to a pipeline; conduct hydrostatic testing for all pipeline segments manufactured using longitudinal seam welds; and use more detailed guidance from PHMSA in the selection of assessment methods to inspect pipelines. The proposed rulemaking also seeks to impose a number of requirements on gathering lines. Additionally, in January 2017, PHMSA promulgated a new final rule regarding hazardous liquid pipelines, which increases the quality and frequency of tests that assess the condition of pipelines, requires operators to annually evaluate the existing protective measures in place for pipeline segments in HCAs, extends certain leak detection requirements for hazardous liquid pipelines not located in HCAs, and expands the list of conditions that require immediate repair. However, it is unclear when or if this rule will go into effect because, on January 20, 2017, the Trump Administration requested that all regulations that had been sent to the Office of the Federal Register, but were not yet published, be immediately withdrawn for further review. Accordingly, this rule has not become effective through publication in the Federal Register. We are monitoring and evaluating the effect of these and other emerging requirements on our operations.

States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the U.S. Department of Transportation (DOT) to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In June 2016, President Obama signed into law new legislation entitled Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (2016 Pipeline Safety Act). The 2016 Pipeline Safety Act

reauthorizes PHMSA through 2019, and facilitates greater pipeline safety by providing PHMSA with emergency order authority, including authority to issue prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities to address imminent hazards, without prior notice or an opportunity for a hearing, as well as enhanced release reporting requirements, requiring a review of both natural gas and hazardous liquid integrity management programs, and mandating the creation of a working group to consider the development of an information-sharing system related to integrity risk analyses. Pursuant to those provisions of the 2016 Pipeline Safety Act, in October 2016 and December 2016, PHMSA issued two separate Interim Final Rules that expanded the agency’s authority to impose emergency restrictions, prohibitions and safety measures and strengthened the rules related to underground natural gas storage facilities, including well integrity, wellbore tubing and casing integrity. The December 2016 Interim Final Rule, relating to underground gas storage facilities, went into effect in January 2017, with a compliance deadline in January 2018. PHMSA determined, however, that it will not issue enforcement citations to any operators for violations of provisions of the December 2016 Interim Final Rule that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issues a final rule. In October 2017, PHMSA formally reopened the comment period on the December 2016 Interim Final Rule in response to a petition for reconsideration, with comments due in November 2017.

Regulation of Environmental and Occupational Safety and Health Matters

General

Our natural gas gathering and water services activities are subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:


•	requiring the installation of pollution-control equipment, imposing emission or discharge limits or otherwise restricting the way we operate resulting in additional costs to our operations;


•	limiting or prohibiting construction activities in areas, such as air quality nonattainment areas, wetlands, coastal regions, endangered species habitat and other protected areas;


•	delaying system modification or upgrades during review of permit applications and revisions;


•	requiring investigatory and remedial actions to mitigate discharges, releases or pollution conditions associated with our operations or attributable to former operations; and


•	enjoining operations deemed to be in non-compliance with permits issued pursuant to, or regulatory requirements imposed by, such environmental laws and regulations.

Failure to comply with these laws and regulations could result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties and damages. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or solid wastes have been disposed or otherwise released. Moreover, neighboring landowners and other third parties may file common law claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other pollutants into the environment.

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 different from the amounts we currently anticipate. As with the midstream industry in general, complying with current and anticipated environmental laws and regulations can increase our costs to construct, maintain and operate equipment and facilities. While these laws and regulations affect our capital expenditures and net income, we do not believe they will have a material adverse effect on our business, financial position or results of operations or cash flows, nor do we believe that they will affect our competitive position since the operations of our competitors are generally similarly affected. In addition, we do not believe that the various activities in which we are presently engaged that are subject to environmental laws and regulations will materially interrupt or diminish our operational ability to gather natural gas or obtain and deliver water. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations, or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of the material environmental laws and regulations that relate to our business.

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. Our anchor customer, EQT, regularly uses hydraulic fracturing as part of its operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but, in response to increased public concern regarding the alleged potential impacts of hydraulic fracturing, the U.S. Environmental Protection Agency (EPA) has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (SDWA) over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. The EPA has also issued final regulations under the federal Clean Air Act (CAA) establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, published a notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing, and finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. The EPA announced its intention to reconsider the CAA performance standards rule in April 2017 and has sought to stay its requirements; however, the rule remains in effect. These rules, if not changed or withdrawn, will continue to require changes to our operations, including the installation of new equipment to control emissions. In addition, the Bureau of Land Management (BLM) finalized rules in March 2015 that imposed new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The BLM rule was struck down by a federal court in Wyoming in June 2016, but reinstated on appeal by the Tenth Circuit in September 2017. While this appeal was pending, the BLM proposed a rulemaking in July 2017 to rescind these rules in their entirety. Although the BLM published a final rule rescinding the 2015 rules in December 2017, other federal or state agencies may look to the BLM rule in developing new regulations that could apply to our operations.

Various state and federal agencies are studying the potential environmental impacts of hydraulic fracturing. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report, contrary to several previously published draft reports issued by the EPA, found instances in which impacts to drinking water may occur. However, the report also noted significant data gaps that prevented the EPA from determining the extent or severity of these impacts. The results of such reviews or studies could spur initiatives to further regulate hydraulic fracturing.

Presently, hydraulic fracturing is regulated primarily at the state level, typically by state oil and natural gas commissions and similar agencies. In July 2015, the Ohio Department of Natural Resources issued final rules for horizontal drilling well-pad construction. Ohio, Pennsylvania (where we conduct a majority of our operations), and Texas have all adopted laws and proposed regulations that require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition to more stringent well construction and monitoring requirements. In addition, in January 2016, the Pennsylvania Department of Environmental Protection (PADEP) issued new rules establishing stricter disposal requirements for wastes associated with hydraulic fracturing activities, which include, among other things, a prohibition on the use of centralized impoundments for the storage of drill cuttings and waste fluids. Further, these rules include requirements relating to storage tank vandalism, secondary containment for storage vessels, construction rules for gathering lines and horizontal drilling under streams, and temporary transport lines for freshwater and wastewater. Moreover, local governments may also adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. The adoption of new laws, regulations or ordinances at the federal, state or local levels imposing more stringent restrictions on hydraulic fracturing could make it more difficult for our customers to complete natural gas wells, increase our customers' costs of compliance and doing business, and otherwise adversely affect the hydraulic fracturing services they perform, which could negatively impact demand for our gathering, transmission, storage and water services.

If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where our customers operate, our customers could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells. Any such added costs, delays or restrictions for our customers could significantly affect our operations. In addition, if the amount of water needed to hydraulically fracture wells is unavailable or if flowback water disposal options become more limited, our customers may experience added costs or delays, which could significantly affect our operations.

Hazardous Waste

The federal Resource Conservation and Recovery Act (RCRA), and comparable state laws, impose requirements for the handling, storage, treatment and disposal of nonhazardous and hazardous waste. RCRA currently exempts certain wastes associated with the exploration, development or production of crude oil and natural gas, which we handle in the course of our operations, including produced water. However, these oil and gas exploration and production wastes may still be regulated by the EPA or state agencies under RCRA’s less stringent nonhazardous solid waste provisions or other federal laws, or state laws,

and it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous waste in the future. For example, from time to time certain environmental groups have petitioned or sued the EPA to remove the RCRA’s exemption for wastes associated with the exploration, development or production of crude oil and natural gas. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires the EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. If such changes were to occur, it could have a significant impact on our operating costs, as well as the natural gas and oil industry in general. Moreover, some ordinary industrial wastes which we generate, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous wastes if they have hazardous characteristics.

S ite Remediation

We currently own, lease or operate, and may have in the past owned, leased or operated, properties that have been used for the gathering of natural gas. Although we typically used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such substances have been taken for disposal. Such petroleum hydrocarbons or wastes may have migrated to property adjacent to our owned and leased sites or the disposal sites. In addition, some of the properties may have been operated by third parties or by previous owners whose treatment and disposal or release of petroleum hydrocarbons or wastes was not under our control.

The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Under CERCLA, such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations, such as landfills. CERCLA authorizes the EPA, states, and, in some cases, third parties to take actions in response to releases or threatened releases of hazardous substances into the environment and to seek to recover from the classes of responsible persons the costs they incur to address the release. Under CERCLA, we could be subject to strict joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released into the environment and for damages to natural resources, and 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. In some states, including Pennsylvania, site remediation of oil and natural gas facilities is regulated by state agencies with jurisdiction over oil and natural gas operations. The regulated releases and remediation activities, including the classes of persons that may be held responsible for releases of hazardous substances, may be broader than those regulated under CERCLA or RCRA.

Although natural gas is excluded from CERCLA’s definition of “hazardous substance,” in the course of our ordinary operations we may handle substances or wastes designated as hazardous. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed wastes, including waste disposed of by prior owners or operators; remediate contaminated property, including groundwater contamination, whether from prior owners or operators or other historic activities or spills; or perform remedial operations to prevent future contamination. We are not currently a potentially responsible party in any federal or state Superfund site remediation and there are no current, pending or anticipated Superfund response or remedial activities at our facilities.

Air Emissions

The CAA, and comparable state laws, regulate emissions of air pollutants from various industrial sources, including natural gas processing plants and compressor stations, and also impose various preconstruction requirements, emission limits, operational limits and monitoring, reporting and recordkeeping requirements on air emission sources. Recently, in October 2015, the EPA lowered the National Ambient Air Quality Standard (NAAQS) for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Failure to comply with these requirements could result in monetary penalties, injunctions, conditions or restrictions on operations, and/or criminal enforcement actions. Such laws and regulations, for example, require preconstruction permits, such as Prevention of Significant Deterioration, or PSD permits, for the construction or modification of certain projects or facilities with the potential to emit air pollutants above certain thresholds. Preconstruction permits generally require use of best available control technology (BACT) to limit air emissions. Several federal and state new source performance standards and national emission standards for hazardous air pollutants and analogous

state law requirements also apply to our facilities and operations. These applicable federal and state standards impose emission limits and operational limits as well as detailed testing, recordkeeping and reporting requirements on the facilities subject to these regulations. Several of our facilities are “major” facilities requiring Title V operating permits which impose semi-annual reporting requirements, but the number of such facilities could grow in the future. For example, in June 2016, the EPA finalized rules under the CAA regarding criteria for aggregating multiple sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities (such as tank batteries and compressor stations), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays or require us to install costly pollution control equipment. Also, in December 2016, the PADEP announced that the agency intends to issue a new general permit for oil and gas exploration, development, and production facilities and liquids loading activities, requiring best available technology for equipment and processes, enhanced record-keeping, and quarterly monitoring inspections for the control of methane emissions. The PADEP issued “draft-final” language for methane reductions from the oil and gas section in November 2017, and intends to issue similar methane rules for existing sources. The PADEP also proposed a new general permit for compressor stations that includes noise minimization requirements.

We may incur capital expenditures in the future for air pollution control equipment in connection with complying with existing and recently proposed rules, or with obtaining or maintaining operating or preconstruction permits and complying with federal, state and local regulations related to air emissions (including air emission reporting requirements). However, we do not believe that such requirements will have a material adverse effect on our operations and we believe such requirements will not be any more burdensome to us than to other similarly situated companies.

Water Discharges

The Federal Water Pollution Control Act, or the Clean Water Act (CWA), and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including sediment, and spills and releases of oil, brine and other substances into waters of the United States. The discharge of pollutants into jurisdictional waters or wetlands is prohibited except in accordance with the terms of a permit issued by the EPA, the U.S. Army Corps of Engineers or a delegated state agency. In September 2015, new EPA and U.S. Army Corps of Engineers rules defining the scope of the EPA’s and the U.S. Army Corps of Engineers’ jurisdiction became effective (2015 Clean Water Rule). To the extent the rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the reach of CWA programs, and implementation of the rule has been stayed pending resolution of the court challenge. In November 2017, the EPA and the U.S. Army Corps of Engineers proposed the addition of an applicability date to the 2015 Clean Water Rule that would be two years after the date of a final rule. This change, if adopted, would effectively prevent the rule from coming back into effect immediately if the stay is lifted. The process for obtaining permits has the potential to delay our operations. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with permits or other requirements of the CWA and analogous state laws and regulations. We believe that we maintain all required discharge permits necessary to conduct our operations. Any unpermitted release of petroleum or other pollutants from our operations could result in government penalties and administrative, civil or criminal liability.

Occupational Safety and Health Act

We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA). Specifically, OSHA’s hazard communication standard, the Emergency Planning and Community Right-to-Know Act and implementing regulations, and similar state statutes and regulations, require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to state and local government authorities and citizens. Certain of 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 material.

Endangered Species and Migratory Bird Treaty Act

The Endangered Species Act (ESA) and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Some of our pipelines are located in areas that are or may be designated as protected habitats for endangered or threatened species, including the Indiana Bat, which has a seasonal impact on our construction activities and operations. The future listing of previously unprotected species in areas where we conduct or may conduct operations, or the designation of critical habitat in these areas, could cause us to incur increased costs arising from species protection measures or could result in limitations on our operating activities, which could have an adverse impact on our results of operations. For example, in April 2015, the U.S. Fish and Wildlife Service listed the northern long-eared bat, whose habitat includes the areas in which we operate, as a threatened

species under the ESA. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas that lay within our areas of operation.

Climate Change

In December 2009, the EPA determined that emissions of greenhouse gases (GHGs) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under existing provisions of the CAA that establish pre-construction and operating permit requirements for GHG emissions from certain large stationary sources. Under these regulations, for example, facilities required to obtain Prevention of Significant Deterioration (PSD) permits because they are potential major sources of criteria pollutants must comply with BACT-driven GHG permit limits established by the states or, in some cases, by the EPA, on a case-by-case basis. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain onshore oil and natural gas processing and fractionating facilities, as well as gathering and boosting facilities. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule. Also, in May 2016, the EPA finalized rules that impose volatile organic compound emissions limits (and collaterally reduce methane emissions) on certain types of compressors and pneumatic pumps, as well as requiring the development and implementation of leak monitoring plans for compressor stations. The EPA announced its intention to reconsider certain of these rules in April 2017 and has sought to stay their requirements; however, the rules remain in effect. These regulations, if not changed or withdrawn, will continue to require changes to our operations, including the installation of new equipment to control emissions. The EPA has also announced that it intends to pursue, but has not yet proposed, methane emission standards for existing sources in addition to new sources. Several states are also pursuing similar measures to regulate emissions of GHGs from new and existing sources. If enacted or promulgated, additional GHG regulations could impose new compliance costs and permitting burdens on our operations.

Also, in November 2016, the BLM finalized, and in December 2016 the PADEP announced that it intends to propose rules related to the control of methane emissions. Certain provisions of the BLM rule went into effect in January 2017, while others were scheduled to go into effect in January 2018. In December 2017, BLM published a final rule delaying the 2018 provisions until 2019. The final draft of the PADEP rule was released in November 2017, and the PADEP hopes to finalize the regulations in early 2018. Compliance with rules to control methane emissions will likely require enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks, and the increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require hiring additional personnel to support these activities or the engagement of third party contractors to assist with and verify compliance. These new rules could result in increased compliance costs on our operations. The PADEP also recently announced an initiative to restrict methane emissions from natural gas development activities. Under the proposed changes, operators in Pennsylvania would need to (i) obtain an air quality general permit in advance of operations, (ii) control releases, and (iii) report emissions.

Additionally, while Congress has from time to time considered legislation to reduce emissions of GHGs, the prospect for adoption of significant legislation at the federal level to reduce GHG emissions is perceived to be low at this time. However, many states have adopted cap and trade programs or renewable energy portfolio standards in an effort to reduce GHG emissions, and these efforts are likely to continue absent additional federal action. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that limit emissions of GHGs could adversely affect demand for the oil and natural gas that exploration and production operators produce, some of whom are our customers, which could thereby reduce demand for our midstream services. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if any such effects were to occur, it is uncertain if they would have an adverse effect on our business, financial condition, results of operations, liquidity or ability to make distributions to our unitholders.

Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue.

Employees

We do not have any employees. We are managed by the directors and officers of our general partner. All executive management personnel of our general partner are officers of EQT and devote the portion of their time to our business and affairs that is required to manage and conduct our operations. Our daily business operations are conducted by employees of EQT's operating subsidiaries. Under the terms of our omnibus agreement with EQT, we reimburse EQT for the provision of general and administrative services for our benefit, for direct expenses incurred by EQT on our behalf, for expenses allocated to

us as a result of it being a public entity and for operation and management services provided by EQT's operating subsidiaries. Additionally, we have an employee secondment agreement with EQT whereby EQT and its subsidiaries provide seconded employees to perform certain operating and other services with respect to our business.

Insurance

We generally share insurance coverage with EQT. We reimburse EQT for the cost of the insurance pursuant to the terms of our omnibus agreement with EQT. The insurance program includes excess liability insurance, auto liability insurance, workers’ compensation insurance and property insurance. In addition, we have procured separate general liability and directors and officers liability policies. All insurance coverage is in amounts management believes to be reasonable and appropriate.

Facilities

EQT’s corporate headquarters are in Pittsburgh, Pennsylvania. Pursuant to our omnibus agreement with EQT, we reimburse EQT for our proportionate share of EQT’s costs to lease the building.

Available Information

Our website is available at www.ricemidstream.com. Information contained on or connected to our website is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this Annual Report on Form 10-K or any other filing we make with the SEC. We make available, free of charge, on our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments and exhibits to those reports, as soon as reasonably practicable after filing such reports with the SEC. Other information such as our Corporate Governance Guidelines, the charter of our Audit Committee and our Code of Business Conduct and Ethics are available on our website and in print to any unitholder who provides a written request to our Corporate Secretary at 625 Liberty Avenue, Suite 1700, Pittsburgh. Pennsylvania 15222.

The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains a website that contains reports and information statements, and other information regarding issuers that file electronically with the SEC. The public can obtain any document that we file with the SEC at www.sec.gov.

Composition of Segment Operating Revenues

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



	Successor		Predecessor
	Period from November 13, 2017 to December 31, 2017		Period from January 1, 2017 to November 12, 2017		Years Ended December 31,
Operating revenues:	Period from November 13, 2017 to December 31, 2017		Period from January 1, 2017 to November 12, 2017		2016		2015
Gathering and compression	69	%	67	%	66	%	67	%
Water services	31	%	33	%	34	%	33	%

Financial Information about Segments

Please see Note 10 to the Consolidated Financial Statements in this Annual Report for financial information by business segment including, but not limited to, revenues from external customers, operating income and total assets, which information is incorporated herein by reference.

Jurisdiction and Year of Formation

Rice Midstream Partners LP is a Delaware limited partnership formed in August 2014.

Financial Information about Geographic Areas

All of our assets and operations are located in the continental United States.

Item 1A. Risk Factors

In addition to the other information contained in this Annual Report, the following risk factors should be considered in evaluating our business and future prospects. Please note that additional risks not presently known to us or that are currently

considered immaterial may also have a negative impact on our business and operations. If any of the events or circumstances described below actually occurs, our business, financial condition, results of operations, liquidity or ability to make distributions to our unit holders could suffer and the trading price of our common units could decline. The risk factor information presented below reflects the impacts of the Mergers.

Risks Related to Our Business

Because a substantial majority of our revenue currently is, and over the long term is expected to be, derived from EQT, any development that materially and adversely affects EQT’s operations, financial condition or market reputation could have a material and adverse impact on us.

For the year ended December 31, 2017 , EQT accounted for substantially all of our gas gathering and compression revenues and 96% of our water services revenues, inclusive of the results of Rice Energy for periods prior to the Mergers. We are substantially dependent on EQT as our most significant customer, and we expect to derive a substantial majority of our revenues from EQT for the foreseeable future. As a result, any event, whether in our dedicated areas or otherwise, that adversely affects EQT’s production and drilling schedule, financial condition, leverage, market reputation, liquidity, results of operations or cash flows may adversely affect our revenues and cash available for distribution. Accordingly, we are indirectly subject to the business risks of EQT, including the following:


•	natural gas price volatility or a sustained period of lower commodity prices may have an adverse effect on EQT's drilling operations, revenue, profitability, future rate of growth and liquidity;


•	a reduction in or slowing of EQT’s anticipated drilling and production schedule, which would directly and adversely impact demand for our services;


•	infrastructure capacity constraints and interruptions;


•	risks associated with the operation of EQT's wells, pipelines and facilities, including potential environmental liabilities;


•	the availability of capital on a satisfactory economic basis to fund EQT's operations;


•	EQT's ability to identify exploration, development and production opportunities based on market conditions;


•	uncertainties inherent in projecting future rates of production;


•	EQT's ability to develop additional reserves that are economically recoverable, to optimize existing well production and to sustain production;


•	adverse effects of governmental and environmental regulation, changes in tax laws and negative public perception regarding EQT's operations;


•	the loss of key personnel; and


•	risk associated with cyber security threats.

Further, we are subject to the risk of non-payment or non-performance by EQT, including with respect to our gathering and compression agreements and water services agreements. We cannot predict the extent to which EQT’s business would be impacted if conditions in the energy industry were to deteriorate, nor can we estimate the impact such conditions would have on EQT’s ability to execute its drilling and development program or perform under our gas gathering and compression agreements or our water services agreements with EQT. Any material non-payment or non-performance by EQT could reduce our ability to make distributions to our unitholders.

Also, due to our relationship with EQT, our ability to access the capital markets, or the pricing or other terms of any capital markets transactions, may be adversely affected by any impairment to EQT’s financial condition or adverse changes in its credit ratings. Any material limitation on our ability to access capital as a result of such adverse changes at EQT could limit our ability to obtain future financing under favorable terms, or at all, or could result in increased financing costs in the future. Similarly, material adverse changes at EQT could negatively impact our unit price, limiting our ability to raise capital through equity issuances or debt financing, or could negatively affect our ability to engage in, expand or pursue our business activities, and could also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.

Unless we are successful in attracting significant unaffiliated third-party customers, our ability to maintain or increase the capacity subscribed and the volumes gathered on our gathering system will be dependent on receiving consistent or

increasing commitments from EQT. While EQT has dedicated acreage to us, and entered into long-term contracts for the services of our systems, it may determine in the future that drilling in areas outside of our dedicated acreage is strategically more attractive and it is under no contractual obligation to maintain its production dedicated to us. A reduction in the volumes gathered on our systems by EQT could have a material adverse effect on our business, financial condition, results of operations, liquidity or ability to make distributions to our unitholders. In addition, EQT has announced that its board of directors has formed a committee to evaluate options to address EQT's sum-of-the-parts discount, with the results of such review to be announced by the end of March 2018. There can be no assurance regarding the outcome of this review or how such outcome may involve or affect us.

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

We may not generate sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution to our unitholders.

We may not generate sufficient cash flow each quarter to support the payment of the minimum quarterly distribution or to increase our quarterly distributions in the future. 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 volume of natural gas we gather and compress;


•	the volume of fresh water we distribute and produced water we handle;


•	the rates we charge for our gathering services and water services;


•	the market price of natural gas and its effect on EQT’s and third parties’ drilling schedules as well as produced volumes;


•	EQT’s and our third-party customers’ ability to fund their drilling programs;


•	adverse weather conditions;


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


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


•	prevailing economic conditions.

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


•	the level, timing and amounts of capital expenditures we make, which amounts could be impacted by costs of labor and materials;


•	our debt service requirements and other liabilities;


•	our ability to make borrowings under our revolving credit facility to pay distributions;


•	fluctuations in our working capital needs;


•	restrictions on distributions contained in any of our debt agreements;


•	the cost of acquisitions, if any;


•	fees and expenses of our general partner and its affiliates (including EQT) we are required to reimburse;


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


•	other business risks affecting our cash levels.

Because of the natural decline in production from existing wells, our success depends, in part, on EQT’s ability to replace declining production and our ability to secure new sources of production from EQT or third parties. Additionally, our water

services are directly associated with EQT’s well completion activities and water needs, which are partially driven by horizontal lateral lengths and the number of completion stages per well. Any decrease in EQT’s production or completion activity could adversely affect our business and operating results.

The natural gas volumes that support our gathering business depend on the level of production from natural gas wells connected to our systems, which may be less than expected and will naturally decline over time. If and to the extent EQT is able to execute its drilling program and achieve its anticipated production targets, the volumes of natural gas we gather should increase. To the extent EQT reduces its activity or otherwise ceases to drill and complete wells, revenues for our gathering and water services will be directly and adversely affected. Our ability to maintain water services revenues is substantially dependent on continued completion activity by EQT and third parties over time, including the volume of fresh water we distribute and produced water we handle for our customers. In addition, natural gas volumes from completed wells will naturally decline over time, and our cash flows associated with these wells will correspondingly decline. In order to maintain or increase throughput levels on our gathering systems, we must obtain new sources of natural gas from EQT or third parties. The primary factors affecting our ability to obtain additional sources of natural gas include (i) decisions by EQT and other producers regarding whether we, EQM or a third party gathers EQT’s or such other producer’s production in acreage that is not dedicated to us, (ii) the success of EQT’s drilling activity or that by other producers in our areas of operation, (iii) EQT’s acquisition of additional acreage that may be dedicated to us, which dedication generally will not be applicable to such additional acquired acreage unless it is in our dedicated areas and acquired by certain subsidiaries of EQT, and (iv) our ability to obtain acreage dedications from third parties. Our fresh water distribution services, which make up a substantial portion of our water services revenues, will be in greatest demand in connection with completion activities. To the extent that EQT or other fresh water distribution customers complete wells with shorter lateral lengths, the demand for our fresh water distribution services would be reduced from that needed for longer lateral lengths.

We have no control over EQT’s or other producers’ level of development and completion activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, our fresh water distribution business is dependent upon active development in our areas of operation. In order to maintain or increase throughput levels on our fresh water distribution systems, we must service new wells. We have no control over EQT or other producers or their development plan decisions, which are affected by, among other things:


•	the availability and cost of capital;


•	prevailing and projected natural gas, NGL and oil prices;


•	the proximity, capacity, cost and availability of gathering and transportation facilities, and other factors that result in differentials to benchmark prices;


•	demand for natural gas, NGLs and oil;


•	levels of reserves;


•	geologic considerations;


•	environmental or other governmental regulations, including the availability of drilling permits, the regulation of hydraulic fracturing, the potential removal of certain federal income tax deductions with respect to natural gas and oil exploration and development or additional state taxes on natural gas extraction; and


•	the costs of producing the natural gas and the availability and costs of drilling rigs and crews and other equipment.

EQT could elect to reduce its drilling activity if commodity prices decrease. Fluctuations in energy prices can also greatly affect the development of reserves. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include worldwide economic conditions, weather conditions and seasonal trends, the levels of domestic production and consumer demand, the levels of imported and exported natural gas, oil and liquefied natural gas, or LNG, the availability of transportation systems with adequate capacity, the volatility and uncertainty of regional pricing differentials, 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, oil, LNG and other commodities. Declines in commodity prices could have a negative impact on EQT’s development and production activity, and if sustained, could lead to a material decrease in such activity. Sustained reductions in development or production activity in our areas of operation could lead to reduced utilization of our services.

In addition, substantially all of EQT’s natural gas production is sold to purchasers under contracts with market-based prices. The actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of

location differentials. Location differentials in commodity prices, also known as basis differentials, result from differences between the price used to set the futures price for a commodity and the corresponding sales price at various regional sales points. The differential commonly is related to factors such as product quality, location, transportation capacity availability and contract pricing. Furthermore, the costs associated with securing long-term firm transportation capacity has risen significantly on newer projects. There can be no assurance that the net impact of entering into such arrangements, after giving effect to their costs, will result in more favorable sales prices for EQT’s production in the future than local pricing alternatives.

Due to these and other factors, even if reserves are known to exist in areas serviced by our assets, producers have chosen, and may choose in the future, not to develop those reserves. If reductions in development activity result in our inability to maintain the current levels of throughput on our gathering systems or our water services, or if reductions in lateral lengths result in a decrease in demand for our water services on a per well basis, those reductions could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

Our assets are concentrated in three counties within the Appalachian Basin, making us vulnerable to risks associated with operating in one major geographic area.

We rely on revenues generated from our gathering systems, which are located in Washington and Greene Counties, Pennsylvania, and our water services assets, which are located in Washington and Greene Counties, Pennsylvania and Belmont County, Ohio. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, trucking shortages, availability of produced water disposal sites, market limitations, governmental regulations impacting the use of water in well completion activities, cold weather conditions or interruption of the processing or transportation of natural gas and NGLs.

Insufficient takeaway capacity in the Appalachian Basin could cause decreased producer activity in our dedicated areas. The Appalachian Basin has recently experienced periods in which natural gas production has surpassed local takeaway capacity, resulting in substantial discounts in the price received by producers selling into the Appalachia markets. Although additional Appalachian Basin takeaway capacity has been added in recent years and additional capacity is being constructed, the existing and expected capacity may not be sufficient to keep pace with the increased production caused by drilling in the area. If our customers are unable to secure long-term firm takeaway capacity on major pipelines that connect to our gathering systems to accommodate their growing production and to manage their basis differentials, it could impact their development plans and cause a decrease in throughput on our gathering systems. Any of the aforementioned throughput decreases could have a material adverse effect on our business, financial condition, results of operations, liquidity or ability to make distributions to our unitholders.

Further, a number of areas within the Marcellus Shale have historically been subject to longwall coal mining operations. For example, third parties may conduct longwall coal mining operations near or under EQT’s, our other customers’ or our properties, which could cause subsidence or other damage to EQT’s, our other customers’ or our properties, adversely impact our customers’ drilling or adversely impact our gathering activities. In such event, our or our customers’ operations may be impaired or interrupted, which could have a material adverse effect on our business, financial condition, results of operations, liquidity or ability to make distributions to our unitholders.

Finally, gathering and water services require special equipment and laborers skilled in multiple disciplines, such as equipment operators, mechanics and engineers, among others. The increased levels of production in the Appalachian Basin may result in a shortage of equipment and skilled labor. If we experience such shortages, our labor and equipment costs and overall productivity could be materially and adversely affected. If our equipment or labor prices increase, our results of operations could be materially and adversely affected.

We may not be able to attract additional third-party gathering and compression volumes or opportunities to provide water services, which could limit our ability to grow and increase our dependence on EQT.

Part of our long-term growth strategy includes identifying additional opportunities to offer services to third parties. For the year ended December 31, 2017, EQT (including Rice Energy with respect to the period prior to the Mergers) accounted for substantially all of our gas gathering and compression revenues and 96% of our water services revenues. Our ability to increase throughput on our gathering and water services systems and any related revenue from third parties is subject to numerous factors beyond our control, including competition from third parties and the extent to which we have available capacity when requested by third parties. 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 volumes in our dedicated areas. In addition, some of our competitors for third-party volumes have greater financial resources and access to larger supplies of natural gas than those available to us, which could allow those competitors to price their services more aggressively than we do.

Our efforts to attract new unaffiliated customers may be adversely affected by (i) our relationship with EQT and the fact that a substantial portion of the capacity of our gathering and water services systems will be necessary to service EQT’s production and development and completion schedule, (ii) our desire to provide services pursuant to fee-based contracts and (iii) the existence of current and future dedications to other gatherers by potential third-party customers. As a result, we may not have the capacity to provide services to third parties and/or potential third-party customers may prefer to obtain services purs uant to other forms of contractual arrangements under which we would be required to assume direct commodity exposure.

Increased competition from other companies that provide 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 natural gas gathering systems. Some of our competitors have greater financial resources and may now, or in the future, have access to greater supplies of natural gas than we do. Some of these competitors may expand or construct gathering systems that would create additional competition for the services we provide to our customers. In addition, our customers may develop their own gathering systems instead of using ours. Moreover, EQT and its affiliates, including EQM, are not limited in their ability to compete with us outside of our dedicated areas.

Further, natural gas as a fuel competes with other forms of energy available to end-users, including coal, liquid fuels and renewable and alternative energy. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas gathering services.

All of these competitive pressures could make it more difficult for us to retain our existing customers and/or attract new customers as we seek to expand our business, which could have a material adverse effect on our business, financial condition, results of operations, liquidity or ability to make 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.

We will be required to make capital expenditures to increase our asset base. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to make cash distributions to our unitholders may be diminished or our financial leverage could increase.

In order to increase 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, as a result, we will be unable to raise the level of our future cash distributions. To fund our capital expenditures, we will be required to use cash from our operations and/or incur borrowings. Such uses of cash from our operations will reduce cash available for distribution to our unitholders. Alternatively, we may sell additional common units or other securities to fund our capital expenditures. Our ability to obtain bank financing or our ability to access the capital markets for future equity or debt offerings may be limited by our or EQT’s financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by general economic conditions, contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our 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 unitholder dilution and would 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 prevailing distribution rate. None of our general partner, EQT or any of their respective affiliates is committed to providing any direct or indirect support to fund our growth.

The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow and not solely on 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 a net loss for financial accounting purposes, and conversely, we might fail to make cash distributions during periods when we record net income for financial accounting purposes.

An impairment of goodwill could result in a negative impact on our financial condition and results of operations.

At December 31, 2017, goodwill was approximately $ 1.3 billion , or 47% of our total assets. Goodwill results from acquisitions, and represents the excess of the acquisition consideration over fair value of the net tangible and other identifiable

intangible assets we recorded as a result of the acquisition. Accounting principles generally accepted in the United States (GAAP ) requires us to periodically test goodwill for impairment. If we were to determine that our goodwill were impaired, we would be required to take an immediate charge to earnings with a corresponding reduction of partners’ equity. Such charges could be material to our results of operations and could adversely impact our financial condition and results of operations.

Our construction or purchase of new gathering, water, or other assets may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our business, financial condition, results of operations, liquidity or ability to make distributions to our unitholders.

The construction of additions or modifications to our existing systems and the construction or purchase of new assets involve numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. Financing may not be available on economically acceptable terms or at all. If we undertake these projects, we may not be able to complete them 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. We may construct facilities to capture anticipated future production growth in an area in which such growth does not materialize. As a result, new gathering, water, or other assets may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our business, financial condition, results of operations, liquidity or ability to make distributions to our unitholders. In addition, the construction of additions to our existing assets may require us to obtain new rights-of-way prior to constructing new pipelines or facilities. We may be unable to timely obtain such rights-of-way to connect new natural gas or water supplies to our existing gathering and water systems or capitalize on other attractive expansion opportunities. Further, we do not own all of the land on which our pipelines and facilities are or may be constructed, and we are, therefore, subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. Additionally, it may become more expensive for us to obtain new rights-of-way or to expand or renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

Our exposure to commodity price risk may change over time.

We currently generate all of our gathering and compression revenues pursuant to fee-based contracts under which we are paid based on the volumes that we gather and compress, rather than the underlying value of the commodity. Consequently, our existing operations and cash flows have no direct exposure to commodity price risk. Although we intend to enter into similar fee-based contracts with new customers in the future, our efforts to negotiate such contractual terms may not be successful. In addition, we may acquire or develop additional midstream assets in a manner that increases our exposure to commodity price risk. Future exposure to the volatility of natural gas, NGL and oil prices could have a material adverse effect on our business, financial condition, results of operations, liquidity or ability to make distributions to our unitholders. However, we have some indirect exposure to commodity prices and basis differentials in that persistently low realized sales prices by our customers may cause them to delay drilling or shut in production, which would reduce the volumes of natural gas available for gathering and compression on our systems. Please read “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.”

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

Our revolving credit facility contains various covenants and restrictive provisions that limit our ability to, among other things:


•	incur or guarantee additional debt;


•	redeem or repurchase units or make distributions under certain circumstances;


•	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 revolving credit facility also contains covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and there is no assurance that that we will meet any such ratios and tests.

The provisions of our revolving 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 revolving 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. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity.”

Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

Our future 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 (including required well pad connections and well connections pursuant to our gas gathering and compression agreements as well as 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 any future indebtedness, we will be forced to take actions such as reducing distributions to our unitholders, reducing or delaying our business activities, investments or capital expenditures, selling assets or issuing equity. We may not be able to effect any of these actions on satisfactory terms or at all.

Increases in interest rates could adversely affect our business, our unit price and our ability to issue additional equity, to incur debt to capture growth opportunities or for other purposes, or to make cash distributions to our unitholders at our intended levels.

If interest rates rise, the interest rates on our revolving credit facility, 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 the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related 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 and our ability to issue additional equity, to incur debt to expand or for other purposes, or to make cash distributions at our intended levels.

The credit and risk profile of 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 EQT may be a factor considered in credit evaluations of us. This is because 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 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 EQT, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service may consider the leverage and credit profile of EQT and its affiliates because of their ownership interest in and control of us. Any adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which would impair our ability to grow our business and make distributions to our unitholders.

If we are unable to make acquisitions on economically acceptable terms from third parties, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our cash available for distribution 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 ability to acquire midstream energy assets from industry participants. In that regard, EQT has publicly announced its intention to sell Rice Energy’s retained

midstream assets acquired by EQT in connection with the Mergers to EQM. Furthermore, many other factors could impair our access to future midstream assets and the willingness of EQT to offer us acquisition opportunities, including EQT’s relationship with EQM and EQGP, a change in control of EQT or a transfer of the incentive distribution rights held by EQT. Any material reduction in opportunities offered to us to acquire midstream assets would limit our future growth and our ability to increase distributions.

If we are unable to make accretive acquisitions, whether because, among other reasons, (i) EQT elects not to sell or contribute additional assets 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 available for distribution on a per unit basis.

Any acquisition involves potential risk. The risks include, 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;


•	limitations on rights to indemnity from the seller;


•	mistaken assumptions about the overall costs of equity or debt;


•	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 cash available for distribution per unit, it could have a material adverse effect on our business, financial condition, results of operations, liquidity or ability to make distributions to our unitholders.

The demand for the services provided by our water distribution business could decline as a result of several factors.

Our water services business includes fresh water distribution for use in our customers’ natural gas, NGL and oil exploration and production activities. Water is an essential component of natural gas, NGL and oil production during the drilling, and in particular, the hydraulic fracturing process. As a result, the demand for our fresh water distribution and produced water handling services is tied to the level of drilling and completion activity of our customers, including EQT, which is currently and will continue to be our primary customer for such services. More specifically, the demand for our water distribution and produced water handling services could be adversely affected by any reduction in or slowing of EQT’s or other customers’ well completions, any reduction in produced water attributable to completion activity, or to the extent that EQT or other customers complete wells with shorter lateral lengths, which would lessen the volume of fresh water required for completion activity.

Additionally, we depend on EQT to source a portion of the fresh water we distribute. The availability of our and EQT’s water supply may be limited due to reasons including, but not limited to, prolonged drought. Restrictions on the ability to obtain water or changes in wastewater disposal requirements may incentivize water recycling efforts by oil and natural gas producers, which could decrease the demand for our fresh water distribution services.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of such assets, which may cause our revenues to decline and our operating expenses to increase.

Our natural gas gathering operations are exempt from regulation by the FERC, under the NGA. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by the FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests the FERC has used to determine whether a pipeline is a gathering pipeline not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is often the subject of litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by the FERC, the courts, or Congress. If the FERC

were to determine that all or some of our gathering facilities and/or services provided by us are not exempt from FERC regulation, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC, which could in turn decrease revenue, increase operating costs, and, depending upon the facility in question, adversely affect our results of operations and cash flows.

Other FERC regulations may indirectly impact our businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, ratemaking, gas quality, capacity release and market center promotion, may indirectly affect the intrastate natural gas market. Should we fail to comply with any applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines, which could have a material adverse effect on our business, financial condition, results of operations, liquidity or ability to make distributions to our unitholders. FERC is authorized to impose civil penalties of up to approximately $1.2 million per violation, per day for violations of the NGA, the NGPA or the rules, regulations, restrictions, conditions and orders promulgated under those statutes. This maximum penalty authority established by statute will continue to be adjusted periodically for inflation.

State regulation of natural gas gathering facilities and intrastate transportation pipelines generally includes various safety, environmental and, in some circumstances, nondiscriminatory take and common purchaser requirements, as well as complaint-based rate regulation. While we have not obtained a specific determination from the applicable state regulators, we believe our natural gas gathering facilities are not subject to rate regulation or open access requirements by state regulators. However, state regulators, such as the Pennsylvania Public Utilities Commission may require us to register as pipeline operators, pay assessment and registration fees, undergo inspections and report annually on the miles of pipeline we operate. Other state regulations may not directly apply to our business, but may nonetheless affect the availability of natural gas for purchase, compression and sale.

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. Our gathering operations could be adversely affected in the future should we become subject to the application of state or federal regulation of rates and services. These operations may also be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of such facilities. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes. For more information regarding federal and state regulation of our operations, please read “Item 1. Business-Regulation of Operations.”

Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas, NGL and oil production by our customers, which could reduce the throughput on our gathering systems, the number of wells for which we provide water services, which could and adversely impact our revenues.

All of EQT’s natural gas production gathered by us is being developed from shale formations. These reservoirs require hydraulic fracturing completion processes to release the liquids and natural gas from the rock so it can flow through casing to the surface.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. Our anchor customer, EQT, regularly uses hydraulic fracturing as part of its operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions and similar agencies, but, in response to increased public concern regarding the alleged potential impacts of hydraulic fracturing, the EPA has asserted federal regulatory authority pursuant to SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. The EPA has also issued final regulations under the CAA establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, published a notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing, and finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. The EPA announced its intention to reconsider the CAA performance standards rule in April 2017 and has sought to stay its requirements. However, the rule remains in effect. These rules, if not changed or withdrawn, will continue to require changes to our operations, including the installation of new equipment to control emissions. In addition, the BLM finalized rules in March 2015 that imposed new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The BLM rule was struck down by a federal court in Wyoming in June 2016, but reinstated on appeal by the Tenth Circuit in September 2017. While this appeal was pending, the BLM proposed a rulemaking in July 2017 to rescind these rules in their entirety. Although the BLM published a final rule rescinding the 2015 rules in December 2017, other federal or state agencies may look to the BLM rule in developing new regulations that could apply to our operations.

Along with several other states, Pennsylvania (where we currently operate) has adopted laws and regulations that impose more stringent disclosure and well construction requirements on hydraulic fracturing operations, and local governments may also adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular, or prohibiting such activities. In addition, various studies are underway by the EPA and other federal agencies concerning the potential environmental impacts of hydraulic fracturing activities. At the same time, certain environmental groups have advocated for additional laws to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed by members of Congress from time to time to provide for such regulation. We cannot predict whether any such legislation will be enacted and if so, what its provisions would require. Additional levels of regulation and permits potentially required by new laws and regulations at the federal, state or local level could lead to delays, increased operating costs and process prohibitions for EQT or other potential customers that could reduce the volumes of natural gas that move through our gathering systems or reduce the number of wells drilled and completed that require fresh water for hydraulic fracturing systems, which in turn could materially adversely affect our revenues and results of operations.

Our operations, as well as our customers’ operations, are subject to significant liability under, or costs and expenditures to comply with, environmental and worker health and safety regulations, which are complex and subject to frequent change.

As an owner, lessee or operator of gathering pipelines and compressor stations, we are subject to various stringent federal, state, and local laws and regulations relating to the discharge of materials into, and protection of, the environment. Numerous governmental authorities, such as 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 response actions. These laws and regulations may impose numerous obligations that are applicable to our and our customers’ 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 or our customers’ operations, the imposition of specific standards addressing worker protection, and the imposition of substantial liabilities and remedial obligations for pollution or contamination resulting from our and our customers’ operations. Failure to comply with these laws, regulations and permits may result in joint and several, strict liability for administrative, civil and/or criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations. Private parties, including the owners of the properties through which our gathering systems pass and facilities where wastes resulting from our operations are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws, regulations and permits or for personal injury or property damage. We may not be able to recover all or any of these costs from insurance. We may also experience a delay in obtaining or be unable to obtain required permits, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenues, which in turn could affect our profitability. In addition, our customers’ liability under, or costs and expenditures to comply with, environmental and worker health and safety regulations could lead to delays and increased operating costs, which could reduce the volumes of natural gas that move through our gathering systems. There is no assurance that changes in or additions to public policy regarding the protection of the environment will not have a significant impact on our operations and profitability.

Our operations also pose risks of environmental liability due to leakage, migration, releases or spills from our operations to surface or subsurface soils, surface water or groundwater. Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons, or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. Please read “Item 1. Business—Regulation of Environmental and Occupational Safety and Health Matters” for more information.

Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the natural gas that we gather, while potential physical effects of climate change could disrupt our operations and cause us to incur significant costs in preparing for or responding to those effects.

In December 2009, the EPA determined that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under existing provisions of the CAA that establish pre-construction and operating permit requirements for GHG emissions from certain large stationary sources. Under these regulations, for example, facilities required to obtain PSD permits because they are potential major sources of criteria pollutants must comply with BACT-driven GHG permit limits established by the states or, in some cases, by the EPA, on a case-by-case basis. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain onshore oil and natural gas processing and fractionating facilities as well as gathering and boosting facilities. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule. Also, in May 2016, the EPA finalized rules that impose volatile organic compound emissions limits (and collaterally reduce methane emissions) on certain types of compressors and pneumatic pumps, as well as requiring the development and implementation of leak monitoring plans for compressor stations. The EPA announced its intention to reconsider certain of the rules in April 2017 and has sought to stay their requirements. However, the rules remain in effect. These regulations, if not changed or withdrawn, will continue to require changes to our operations, including the installation of new equipment to control emissions. Several states are also pursuing similar measures to regulate emissions of GHGs from new and existing sources. If enacted or promulgated, additional GHG regulations could impose new compliance costs and permitting burdens on our operations.

Also, in November 2016, the BLM finalized, and in December 2016 the PADEP announced that it intends to propose, rules related to the control of methane emissions. Certain provisions of the BLM rule went into effect in January 2017, while others were scheduled to go into effect in January 2018. In December 2017, the BLM published a final rule delaying the 2018 provisions until 2019. The final draft of the PADEP rule was released in November 2017, and the PADEP hopes to finalize the regulations in early 2018. Compliance with rules to control methane emissions will likely require enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks, and the increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require hiring additional personnel to support these activities or the engagement of third party contractors to assist with and verify compliance. These new rules could result in increased compliance costs on our operations. The PADEP also recently announced an initiative to restrict methane emissions from natural gas development activities. Under the proposed changes, operators in Pennsylvania would need to (i) obtain an air quality general permit in advance of operations, (ii) control releases, and (iii) report emissions.

Additionally, while Congress has from time to time considered legislation to reduce emissions of GHGs, the prospect for adoption of significant legislation at the federal level to reduce GHG emissions is perceived to be low at this time. However, many states have adopted cap and trade programs or renewable energy portfolio standards in an effort to reduce GHG emissions, and these efforts are likely to continue absent additional federal action. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that limit emissions of GHGs could adversely affect demand for the oil and natural gas that exploration and production operators produce, some of whom are our customers, which could thereby reduce demand for our midstream services. Finally, it should be noted that scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if any such effects were to occur, it is uncertain if they would have an adverse effect on our business, financial condition, results of operations, liquidity or ability to make distributions to our unitholders.

Negative public perception regarding us and/or the midstream industry could have an adverse effect on our business, financial condition, results of operations, liquidity or ability to make distributions to our unitholders.

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

We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any related pipeline repair or preventative or remedial measures.

The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in HCAs. The regulations require operators to:


•	perform ongoing assessments of pipeline integrity;


•	identify and characterize applicable threats to pipeline segments that could impact an HCA;


•	improve data collection, integration and analysis;


•	repair and remediate the pipeline as necessary; and


•	implement preventive and mitigating actions.

The 2011 Pipeline Safety Act, among other things, increases the maximum civil penalty for pipeline safety violations and 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 HCAs. PHMSA has the authority to impose civil penalties for pipeline safety violations up to a maximum of approximately $200,000 per day for each violation and approximately $2 million for a related series of violations. This maximum penalty authority established by statute will continue to be adjusted periodically to account for inflation. Should our operations fail to comply with PHMSA or comparable state regulations, we could be subject to substantial penalties and fines. States also are pursuing regulatory programs intended to ensure the safety of pipeline infrastructure and construction.

In January 2017, PHMSA announced a new final rule regarding hazardous liquid pipelines, which increases the quality and frequency of tests that assess the condition of pipelines, requires operators to annually evaluate the existing protective measures in place for pipeline segments in HCAs, extends certain leak detection requirements for hazardous liquid pipelines not located in HCAs, and expands the list of conditions that require immediate repair. However, it is unclear when or if this rule will go into effect because, on January 20, 2017, the Trump Administration requested that all regulations that had been sent to the Office of the Federal Register, but were not yet published, be immediately withdrawn for further review. Accordingly, this rule has not become effective through publication in the Federal Register. PHMSA also proposed rules in April 2016 that would, if adopted, impose more stringent requirements for certain gas lines. Among other things, the proposed rulemaking would extend certain of PHMSA’s current regulatory safety programs for gas pipelines beyond HCAs to cover gas pipelines found in newly defined “moderate consequence areas” that contain as few as five dwellings within the potential impact area and would also require gas pipelines installed before 1970 that are currently exempted from certain pressure testing obligations to be tested to determine their MAOP. Other new requirements proposed by PHMSA under the rulemaking would require pipeline operators to: report to PHMSA in the event of certain MAOP exceedances; strengthen PHMSA integrity management requirements; consider seismicity in evaluating threats to a pipeline; conduct hydrostatic testing for all pipeline segments manufactured using longitudinal seam welds; and use more detailed guidance from PHMSA in the selection of assessment methods to inspect pipelines. The proposed rulemaking also seeks to impose a number of requirements on gathering lines. Moreover, in June 2016, President Obama signed the 2016 Pipeline Safety Act into law. The 2016 Pipeline Safety Act reauthorizes PHMSA through 2019, and facilitates greater pipeline safety by providing PHMSA with emergency order authority, including authority to issue prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities to address imminent hazards, without prior notice or an opportunity for a hearing, as well as enhanced release reporting requirements, requiring a review of both natural gas and hazardous liquid integrity management programs, and mandating the creation of a working group to consider the development of an information-sharing system related to integrity risk analyses. Pursuant to those provisions of the 2016 Pipeline Safety Act, in October 2016 and December 2016, PHMSA issued two separate Interim Final Rules that expanded the agency’s authority to impose emergency restrictions, prohibitions and safety measures and strengthened the rules related to underground natural gas storage facilities, including well integrity, wellbore tubing and casing integrity. The December 2016 Interim Final Rule, relating to underground gas storage facilities, went into effect in January 2017, with a compliance deadline in January 2018. PHMSA determined, however, that it will not issue enforcement citations to any operators for violations of provisions of the December 2016 Interim Final Rule that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issues a final rule. In October 2017, PHMSA formally reopened the comment period on the December 2016 Interim Final Rule in response to a petition for reconsideration, with comments due in November 2017. This matter remains ongoing and subject to future PHMSA determinations. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our business, financial condition, results of operations, liquidity or ability to make distributions to our unitholders. We are monitoring and evaluating the effect of these and

other emerging requirements on our operations. Please read “Item 1. Business-Regulation of Operations—Pipeline Safety Regulation” for more information.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. The occurrence of a significant accident or other event that is not fully insured could curtail our operations and have a material adverse effect on our business, financial condition, results of operations, liquidity or ability to make distributions to our unitholders.

Our operations are subject to all of the hazards inherent in the gathering of natural gas, including:


•	damage to pipelines, compressor stations, equipment and surrounding properties caused by hurricanes, earthquakes, tornadoes, floods, fires, landslides and other natural disasters and acts of sabotage and terrorism;


•	damage from construction, farm and utility equipment, as well as other subsurface activity (for example, mine subsidence);


•	leaks of natural gas or losses of natural gas as a result of the malfunction of equipment or facilities;


•	ruptures and explosions;


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


•	hazards experienced by other operators that may affect our operations by instigating increased regulations and oversight.

Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:


•	injury or loss of life;


•	damage to and destruction of property, natural resources and equipment;


•	pollution and other environmental damage;


•	regulatory investigations and penalties;


•	suspension of our operations; and


•	repair and remediation costs.

We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations, liquidity or ability to make distributions to our unitholders.

We do not have any officers or employees apart from those seconded to us and rely solely on officers of our general partner and employees of EQT.

We are managed and operated by the board of directors of our general partner. Affiliates of EQT conduct businesses and activities of their own in which we have no economic interest. As a result, there could be material competition for the time and effort of the officers and employees who provide services to our general partner, EQM, EQM’s general partner, EQGP, EQGP’s general partner and EQT. While we expect the officers and employees who provide services to our general partner to devote sufficient attention to the management and operation of our business, if they do not devote sufficient attention our financial results may suffer, and our ability to make distributions to our unitholders may be reduced.

Terrorist or cyber security attacks or threats thereof aimed at our facilities or surrounding areas could adversely affect our business.

Our business has become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications, to operate our assets, and the maintenance of our financial and other records has long been dependent upon such technologies. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Deliberate attacks on, or unintentional events affecting, our systems or infrastructure, the systems or infrastructure of third parties or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in delivery of natural gas and natural gas liquids, difficulty in completing and settling

transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, personal injury, property damage, other operational disruptions and third party liability. Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.

Risks Related to Our Partnership Structure

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

EQT indirectly owns and controls our general partner and appoints all of the officers and directors of our general partner. All of our officers and a majority of our directors are also officers and/or directors of EQT. Although our general partner has a duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to EQT. Further, our directors and officers who are also directors and officers of EQT have a fiduciary duty to manage EQT in the best interests of the shareholders of EQT. Additionally, EQT also controls EQM’s general partner and EQGP’s general partner and has the power to appoint all of the officers and directors of EQM’s general partner and EQGP’s general partner. Conflicts of interest will arise between EQT and any of its affiliates, including EQM, EQGP, EQM’s general partner, EQGP’s general partner and our general partner, on the one hand, and us and our common unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of EQT, EQM and EQGP over our interests and the interests of our unitholders. These conflicts include the following situations, among others:


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


•	EQT, as our anchor customer, has an economic incentive to cause us not to seek higher gathering fees and water service fees, even if such higher fees would reflect fees that could be obtained in arm’s-length, third-party transactions;


•	EQT may choose to shift the focus of its investment and operations to areas not serviced by our assets, including areas serviced by EQM;


•	EQT may choose to allocate capital and costs among EQGP, EQM and us in a manner that is not favorable to us;


•	actions taken by our general partner may affect the amount of cash available to pay distributions to our unitholders;

•

all of the officers and six of the directors of our general partner are also officers and/or directors of EQT and owe fiduciary duties to EQT; all of the officers and five of the directors of our general partner as also officers and/or directors of EQM’s general partner and owe fiduciary duties to EQM; and three of the officers and four of the directors of our general partner are also officers and/or directors of EQGP’s general partner and owe fiduciary duties to EQGP. The officers of our general partner also devote significant time to the business of EQT, EQM and EQGP and are compensated by EQT accordingly;


•	our general partner is allowed to take into account the interests of parties other than us, such as EQT, in exercising certain rights under our partnership agreement, including with respect to conflicts of interest;


•	except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;


•	our general partner may cause us to borrow funds in order to permit the payment of cash distributions;


•	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, issuances of additional partnership securities and the level of reserves, each of which can affect the amount of cash that is distributed to our unitholders;


•	our general partner determines the amount and timing of any capital expenditure and the amount of estimated maintenance capital expenditures, which reduces operating surplus. The determination of estimated maintenance capital expenditures can affect the amount of cash from operating surplus that is distributed to our unitholders;


•	our partnership agreement limits the liability of, and replaces the duties owed by, our general partner and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;


•	common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us;


•	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;


•	our partnership agreement permits us to distribute up to $35.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to our general partner in respect of the general partner interest or our incentive distribution rights;


•	our general partner determines which costs incurred by it and its affiliates are reimbursable by us;


•	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 its affiliates 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 common units if it and its affiliates own more than 80% of the common units;


•	we may not choose to retain separate counsel for ourselves or for the holders of common units;


•	our general partner’s affiliates, including EQT and EQM, may compete with us and may offer business opportunities and/or sell midstream assets to other affiliates or third parties without first offering us the right to bid for them; and


•	the holder or holders of our incentive distribution rights may elect to cause us to issue common units to it in connection with a resetting of incentive distribution levels without the approval of our unitholders, which may result in lower distributions to our common unitholders in certain situations.

Ongoing cost reimbursements due to our general partner and its affiliates for services provided, which will be determined by our general partner, may be substantial and will reduce our cash available for distribution to our unitholders.

Prior to making distributions on our common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us, including costs for rendering administrative staff and support services to us and reimbursements paid by our general partner to EQT for customary management and general administrative services. There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

We expect to distribute a significant portion of our cash available for distribution to our partners, which could limit our ability to grow and/or make acquisitions.

We plan to distribute most of our cash available for distribution and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our expansion capital expenditures and acquisitions, if any. As a result, to the extent we are unable to finance growth externally, our cash distribution policy may cause our growth to proceed at a slower pace than that of businesses that reinvest their cash to expand ongoing operations. To the extent we issue additional units in connection with any expansion capital expenditures or acquisitions, if any,

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 on our ability to issue additional units, including units ranking senior to the common units. In addition, the incurrence of commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the cash that we have available to distribute to our unitholders.

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.

Our partnership agreement contains provisions that eliminate and replace 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 fiduciary duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the parties where the language in our partnership agreement does not provide for a clear course of action. 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 our limited partners. Examples of decisions that our general partner may make in its individual capacity include:


•	how to allocate business opportunities among us and its other affiliates, including EQT and EQM;


•	whether to exercise its limited call right;


•	whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of the general partner;


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


•	whether to exercise its registration rights; and


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

Limited partners who own common units are treated as having consented to the provisions in the partnership agreement, including the provisions discussed above.

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

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

•

provides that whenever our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner and any committee thereof (including the conflicts committee) is required to make such determination, or take or decline to take such other action, in the absence of bad faith, 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;


•	provides that 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 it acted in good faith, meaning that it believed that the decision was not adverse to the interest of our partnership;

•

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


•	provides that 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; or


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

In connection with 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 approves the affiliate transaction or resolution or course of action taken with respect to the conflict of interest, 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 and proving that such decision was not in good faith.

Our partnership agreement includes exclusive forum, venue and jurisdiction provisions. By purchasing a common unit, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts. Our partnership agreement also provides that any unitholder bringing an unsuccessful action will be obligated to reimburse us for any costs we have incurred in connection with such unsuccessful claim.

Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue and jurisdiction provisions designating Delaware courts as the exclusive venue for most claims, suits, actions and proceedings involving us or the officers, directors and employees of our general partner and its affiliates. If a dispute were to arise between a limited partner and us or the officers, directors or employees of our general partner and its affiliates, the limited partner may be required to pursue its legal remedies in Delaware, which may be an inconvenient or distant location and which is considered to be a more corporate-friendly environment. In addition, if any unitholder brings any of the aforementioned claims, suits, actions or proceedings and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. Limited partners who own common units irrevocably consent to these provisions and potential reimbursement obligations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.

Compared to the holders of common stock in a corporation, our unitholders have limited voting rights and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by EQT, as a result of it indirectly owning our general partner, and not by our unitholders. Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. Unlike publicly-traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

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

Our general partner intends to limit its liability under contractual arrangements between us and third parties 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 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 is required to deduct estimated maintenance capital expenditures from our operating surplus, which may result in less cash available for distribution to unitholders from operating surplus than if actual maintenance capital expenditures were deducted.

Maintenance capital expenditures are those capital expenditures made to maintain, over the long term, our operating capacity or operating income. Our partnership agreement requires our general partner to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus in determining cash available for distribution from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by our general partner’s board of directors at least once a year, provided that any change is approved by the conflicts committee of our general partner’s board of directors. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders from operating surplus will be lower than if actual maintenance capital expenditures had been deducted from operating surplus. On the other hand, if our general partner underestimates the appropriate level of estimated maintenance capital expenditures, we will have more cash available for distribution from operating surplus in the short term but will have less cash available for distribution from operating surplus in future periods when we have to increase our estimated maintenance capital expenditures to account for the previous underestimation.

EQT may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our incentive distribution rights, without the approval of the conflicts committee of our general partner’s board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

EQT has the right, as the holder of our incentive distribution rights, at any time when it has received incentive distributions at the highest level to which it is entitled (50%) for the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be adjusted to equal 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.

If EQT elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of common units to be issued to EQT will equal the number of common units that would have entitled EQT to an aggregate quarterly cash distribution in the quarter prior to the reset election equal to the distribution on the incentive distribution rights in the quarter prior to the reset election. We anticipate that EQT 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. It is possible, however, that EQT 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 distributions based on the initial target distribution levels. 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 a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels. EQT may transfer all or a portion of the incentive distribution rights in the future. After any such transfer, the holder or holders of a majority of our incentive distribution rights will be entitled to exercise the right to reset the target distribution levels.

The incentive distribution rights held by EQT may be transferred to a third party without unitholder consent.

EQT may transfer our incentive distribution rights to a third party at any time without the consent of our unitholders. If EQT transfers our incentive distribution rights to a third party but retains its ownership of our general partner interest, it 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 our 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.

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

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates (including EQT), 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.

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 without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner from transferring all or a portion of their respective ownership interest in our general partner to a third party. The new owners 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 choices and thereby exert significant control over the decisions made by the board of directors and officers. This effectively permits a “change of control” without the vote or consent of the unitholders.

We may issue additional units, including units that are senior to the common units, without unitholder approval, which would dilute our unitholders ’ existing ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests 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:


•	each unitholder’s proportionate ownership interest in us will decrease;


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


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


•	the ratio of taxable income to distributions may increase;


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


•	the market price of the common units may decline.

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

As of February 15, 2018, EQT indirectly held 28,757,246 of our common units, representing a 28% limited partner interest in us. In addition, we have agreed to provide EQT with certain registration rights, pursuant to which we may be required to register common units it holds under the Securities Act and applicable state securities laws. Pursuant to the registration rights agreement and our partnership agreement, we may be required to undertake a future public or private offering of common units. The sale of these units in 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 has a limited call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates (including EQT) own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (i) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (ii) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, or the Exchange Act. As of February 15, 2018, our general partner and its affiliates (including EQT) owned 28% of our outstanding common units.

Our unitholders ’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is

organized under Delaware law, and we currently own assets and conduct business in Pennsylvania and Ohio. A unitholder could be liable for any and all of our obligations as if that unitholder were a general partner if:


•	a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or


•	a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the 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. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.

The market price of our common units may be influenced by many factors, some of which are beyond our control, including:


•	our quarterly distributions;


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


•	events affecting EQT and its affiliates;


•	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 or changes in financial estimates by analysts;


•	future sales of our common units; and


•	other factors described in these “Risk Factors.”

The New York Stock Exchange (NYSE) does not require a publicly-traded partnership like us to comply with certain of its corporate governance requirements.

Our common units are currently traded on the NYSE. Because we are a publicly-traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.

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

As a publicly-traded partnership, we incur significant legal, accounting and other expenses that we did not incur prior to our initial public offering (IPO). In addition, the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the NYSE, require publicly-traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to make distributions to our unitholders, we must first pay or reserve cash for our expenses, including the costs of being a publicly-traded partnership. As a result, the amount of cash we have available for distribution to our unitholders is affected by the costs associated with being a publicly-traded partnership.

As a result of our IPO, we became subject to the public reporting requirements of the Exchange Act. We expect these rules and regulations to increase certain of 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, maintain 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 incur additional costs associated with our SEC reporting requirements.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as us not being subject to a material amount of entity-level taxation. If the IRS were to treat us as a corporation for federal income tax purposes, or if we become subject to entity-level taxation for state tax purposes, our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.

Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. We have requested and obtained a favorable private letter ruling from the IRS to the effect that, based on facts presented in the private letter ruling request, our income from the delivery of water and the collection, treatment, and transport of flowback, produced water, and other fluids constitutes “qualifying income” within the meaning of Section 7704 of the Internal Revenue Code of 1986, as amended (the Code). However, no ruling has been or will be requested regarding our treatment as a partnership for U.S. federal income tax purposes. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. 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 U.S. federal income tax on our taxable income at the corporate tax rate, which is currently 21.0%, and would likely pay state and local income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the 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 U.S. 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. At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. Specifically, we currently own assets and conduct business in Pennsylvania and Ohio. Imposition of a similar tax on us in other jurisdictions that we may expand to could substantially reduce our cash available for distribution to our unitholders.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships.

Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

Our unitholders are required to pay income taxes on their share of our taxable income even if they do not receive any cash distributions from us. A unitholder’s share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, transactions in which we engage or changes in law and may be substantially different from any estimate we make in connection with a unit offering.

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

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

From time to time, in connection with an offering of our common units, we may state an estimate of the ratio of federal taxable income to cash distributions that a purchaser of our common units in that offering may receive in a given period. These estimates depend in part on factors that are unique to the offering with respect to which the estimate is stated, so the expected ratio applicable to other common units will be different, and in many cases less favorable, than these estimates. Moreover, even in the case of common units purchased in the offering to which the estimate relates, the estimate may be incorrect, due to the uncertainties described above, challenges by the IRS to tax reporting positions which we adopt, or other factors. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of our common units.

If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce 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 U.S. federal income tax purposes. The IRS may adopt positions that differ from the conclusions of our counsel expressed in a prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS, and the outcome of any IRS contest, may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it (and some states) may assess and collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case we may require our unitholders and former unitholders to reimburse us for such taxes (including any applicable penalties or interest) or, if we are required to bear such payment, our cash available for distribution to our unitholders might be substantially reduced.

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

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

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

If our unitholders sell their common units, our unitholders will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of our unitholders’ allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units our unitholders sell will, in effect, become taxable income to our unitholders if they sell such units at a price greater than their tax basis in those units, even if the price our unitholders receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if our unitholders sell their common units, our unitholders may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (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. Allocations and/or distributions to non-U.S. persons will be subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person will be required to file United States federal tax returns and pay tax on their share of our taxable income.

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

Tax-exempt entities and non-U.S. persons should consult a tax advisor before investing in our common units.

We will treat each purchaser of common units as having the same tax benefits without regard to the common units actually 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 our 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. 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.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common 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 generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month (the Allocation Date), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. The U.S. Department of the Treasury adopted final Treasury Regulations allowing a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder who disposes of units prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deduction attributable to the month of disposition but will not be entitled to receive a cash distribution for that period.

A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered to have disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and could recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those 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, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We have adopted certain valuation methodologies in determining unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations, and such a challenge could adversely affect the value of our common units.

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

A successful IRS challenge to these methods or allocations could adversely affect the amount, character, and timing of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

As a result of investing in our common units, our unitholders may become subject to state and local taxes and income tax return filing requirements in jurisdictions where they do not live.

In addition to U.S. federal income taxes, our unitholders may be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file foreign, 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 currently own assets and conduct business in Pennsylvania and Ohio, each of which imposes a personal income tax on individuals. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is our unitholders responsibility to file all United States federal, foreign, state and local tax returns.

Compliance with and changes in tax laws could adversely affect our performance.

We are subject to extensive tax laws and regulations, including federal, state and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The information required by Item 2 is contained in “Item 1. Business”.

Item 3. 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 and other direct costs related to loss contingencies when actually incurred. We have established reserves 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 materially affect our business, financial condition, results of operations, liquidity or ability to make distributions.

Environmental Proceedings

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

Item 4. Mine Safety Disclosures

Not applicable.

PART II

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

Our common units are listed on the New York Stock Exchange (NYSE) under the symbol RMP. The following table sets forth the high and low sales prices reflected in the NYSE Composite Transactions of the common units, as reported by the NYSE, as well as the amount of cash distributions declared per quarter for 2017 and 2016 .



	2017						2016
	Unit Price Range				Distributions paid per Common Unit		Unit Price Range				Distributions paid per Common Unit
(in dollars per share)	High		Low		Distributions paid per Common Unit		High		Low		Distributions paid per Common Unit
1st Quarter	$	26.42	$	22.48	$	0.2505	$	15.39	$	8.40	$	0.1965
2nd Quarter	$	26.18	$	16.87	$	0.2608	$	20.65	$	14.21	$	0.2100
3rd Quarter	$	21.50	$	19.52	$	0.2711	$	24.30	$	18.05	$	0.2235
4th Quarter	$	21.99	$	19.69	$	0.2814	$	24.88	$	20.05	$	0.2370

On January 18, 2018 , the Board of Directors of our general partner declared a cash distribution to our unitholders of $0.2917 per common and subordinated unit for the fourth quarter of 2017 . The cash distribution was paid on February 14, 2018 , to unitholders of record at the close of business on February 2, 2018 . Also on February 14, 2018 , a cash distribution of $3.0 million was made to GP Holdings related to its IDRs in the Partnership based upon the level of distribution paid per common and subordinated unit.

The number of unitholders of record of our common units was approximately 89 as of January 31, 2018 . The number of registered holders does not include holders that have common units held for them in “street name,” meaning that the common units are held for their accounts by a broker or other nominee. In these instances, the brokers or other nominees are included in the number of registered holders, but the underlying unitholders that have units are not.

We also issued 28,753,623 subordinated units, which were converted to common units on a one-for-one basis on February 15, 2018. Prior to the conversion, all of the subordinated units were held by GP Holdings. GP Holdings received quarterly distributions on these units only after sufficient distributions had been paid to the holders of common units. Please see Note 7 to the Consolidated Financial Statements for a discussion of the conversion of the subordinated units.

Please see Note 7 to the Consolidated Financial Statements included in this Annual Report for information on the significant provisions of our partnership agreement that relate to distributions of available cash, minimum quarterly distributions and IDRs.

The information relating to our equity compensation plans required by Item 5 is included in Item 12, "Security Ownership of Certain Beneficial Owners and Management" of this Annual Report which is incorporated herein by reference.

We did not repurchase any of our common units during the year ended December 31, 2017 .

Item 6. Selected Financial Data

In connection with the completion of the Mergers, EQT acquired indirect ownership of our general partner resulting in a change of control of our general partner. As a result of the change in control, our assets and liabilities were adjusted to fair value on the Merger Date by application of pushdown accounting and we became a consolidated subsidiary of EQT. Due to the application of pushdown accounting, our consolidated financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented. The periods prior to the Merger Date are identified as Predecessor, and the period from the Merger Date forward is identified as Successor. The following table presents our selected financial and operating data as of the dates and for the periods indicated and should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and related notes, each of which is included in this Annual Report. We believe that the assumptions underlying the preparation of our historical consolidated financial statements are reasonable.



	Successor			Predecessor
	Period from November 13, 2017 to December 31, 2017			Period from January 1, 2017 to November 12, 2017			Years Ended December 31,
(in thousands, except per unit data)	Period from November 13, 2017 to December 31, 2017			Period from January 1, 2017 to November 12, 2017			2016 ⁽²⁾			2015			2014			2013
Statement of operations data:
Total operating revenues	$	44,219		$	250,474		$	201,623		$	114,459		$	6,448		$	498
Operating income (loss)	$	25,945		$	163,478		$	126,942		$	62,036		$	(30,567	)	$	(5,208	)
Net income (loss)	$	25,134		$	152,839		$	121,610		$	52,495		$	(31,328	)	$	(9,012	)
Limited partner net income	$	23,535		$	146,657		$	120,182		$	45,199		$	1,162
Net income attributable to RMP per limited partner unit ⁽¹⁾
Common units (basic)	$	0.23		$	1.43		$	1.46		$	0.76		$	0.02
Common units (diluted)	$	0.23		$	1.43		$	1.45		$	0.76		$	0.02
Subordinated units (basic & diluted)	$	0.23		$	1.43		$	1.50		$	0.76		$	0.02
Cash distributions paid per limited partner unit ⁽¹⁾	$	0.281		$	0.782		$	0.867		$	0.592		$	—
Balance sheet data (at period end):
Total assets	$	2,849,013					$	1,399,217		$	689,790		$	443,091		$	74,445
Revolving credit facility	$	286,000					$	190,000		$	143,000		$	—		$	—
Net cash provided by (used in):
Operating activities	$	22,430		$	150,811		$	154,117		$	70,006		$	(25,021	)	$	(7,186	)
Investing activities	$	(34,553	)	$	(131,421	)	$	(721,087	)	$	(379,991	)	$	(336,273	)	$	(44,244	)
Financing activities	$	9,959		$	(28,522	)	$	581,207		$	290,748		$	387,980		$	51,578

(1)

Net income per limited partner unit and cash distributions per limited partner unit are presented only for the periods subsequent to our initial public offering (IPO) and do not include results attributable to the Water Assets (defined in Note 1 to the Consolidated Financial Statements included in this Annual Report) prior to their acquisition as these results are not attributable to limited partners of the Partnership.


(2)	Includes post-acquisition results of the Vantage Midstream Entities. Please see Note 2 to the Consolidated Financial Statements included in this Annual Report for further detail regarding the Vantage Midstream Asset Acquisition.

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included in Item 8 of this Annual Report. As a result of the Mergers, our assets and liabilities were adjusted to fair value by application of pushdown accounting and we became a consolidated subsidiary of EQT. Due to the application of pushdown accounting, our consolidated financial statements and certain footnote disclosures are in two distinct periods to indicate the application of two different bases of accounting between the periods presented. The periods prior to the Merger Date are identified as Predecessor and the period from the Merger Date forward is identified as Successor. For discussion purposes, we have combined the results of operations for the Successor and Predecessor periods of 2017 because we believe it facilitates the comparison of 2016 and 2015 operating and financial performance to 2017 and because our operations have not changed as a result of the Mergers.

Executive Overview

We reported net income of $178.0 million in the Combined Year 2017 compared with $121.6 million in 2016. The increase primarily resulted from higher revenues from both gathering and water services, partially offset by an increase in operating expenses consistent with the growth of the business and higher interest expense.

We reported net income of $121.6 million in 2016 compared with $52.5 million in 2015. The increase primarily resulted from higher revenues from both gathering and water services, partially offset by an increase in operating expenses consistent with the growth of the business and higher interest expense.

We declared a cash distribution to our unitholders of $0.2917 per unit on January 18, 2018, which was 4% higher than the third quarter 2017 distribution of $0.2814 per unit and 16% higher than the fourth quarter 2016 distribution of $0.2505 per unit. Total distributions related to 2017 were $1.105 per unit compared to $0.921 per unit total distributions related to 2016, a 20% increase.

Results of Operations

The following table sets forth consolidated operating data for the Combined Year ended December 31, 2017 compared to the year ended December 31, 2016 and for the year ended December 31, 2016 compared to the year ended December 31, 2015 :



	Successor			Predecessor			(Unaudited) Combined Year			Predecessor						Predecessor
	Period from November 13, 2017 to December 31, 2017			Period from January 1, 2017 to November 12, 2017			Year Ended December 31, 2017			Year Ended December 31, 2016						Year Ended December 31, 2015			Change
	Period from November 13, 2017 to December 31, 2017			Period from January 1, 2017 to November 12, 2017			Year Ended December 31, 2017			Year Ended December 31, 2016			Change			Year Ended December 31, 2015			Change
Statement of operations: (in thousands)
Operating revenues:
Affiliate	$	44,134		$	203,642		$	247,776		$	152,260		$	95,516		$	93,668		$	58,592
Third-party	85			46,832			46,917			49,363			(2,446		)	20,791			28,572
Total operating revenues	44,219			250,474			294,693			201,623			93,070			114,459			87,164

Operating expenses:
Operation and maintenance expense	7,182			33,768			40,950			24,608			16,342			14,910			9,698
General and administrative expense	3,612			22,252			25,864			21,613			4,251			17,895			3,718
Incentive unit expense	—			—			—			—			—			1,044			(1,044		)
Depreciation expense	7,480			26,420			33,900			25,170			8,730			16,399			8,771
Acquisition costs	—			529			529			125			404			—			125
Amortization of intangible assets	—			1,413			1,413			1,634			(221		)	1,632			2
Other expense	—			2,614			2,614			1,531			1,083			543			988
Total operating expenses	18,274			86,996			105,270			74,681			30,589			52,423			22,258

Operating income (loss)	25,945			163,478			189,423			126,942			62,481			62,036			64,906
Other income (expense)	15			56			71			78			(7		)	11			67
Interest expense	(826		)	(7,053		)	(7,879		)	(3,931		)	(3,948		)	(3,164		)	(767		)
Amortization of deferred financing costs	—			(3,642		)	(3,642		)	(1,479		)	(2,163		)	(576		)	(903		)
Income (loss) before income taxes	25,134			152,839			177,973			121,610			56,363			58,307			63,303
Income tax expense	—			—			—			—			—			(5,812		)	5,812
Net income	$	25,134		$	152,839		$	177,973		$	121,610		$	56,363		$	52,495		$	69,115

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

The factors impacting operating income are discussed in the business segment results.

Interest expense . Interest expense increased from $3.9 million for the year ended December 31, 2016 to $7.9 million for the Combined Year ended December 31, 2017 , an increase of $4.0 million, or 100% . The increase in interest expense was primarily due to the timing of draw-downs on our revolving credit facility. The average borrowing under our revolving credit facility for the Combined Year ended December 31, 2017 and the year ended December 31, 2016 was $216.3 million and $110.0 million , respectively.

Amortization of deferred financing costs. Amortization of deferred financing costs increased from $1.5 million for the year ended December 31, 2016 to $3.6 million for the period from January 1, 2017 through November 12, 2017, an increase of $2.2 million , or 140%. The increase primarily related to the timing financing costs incurred associated with equity offerings and amendments to our revolving credit facility. At the Merger Date, the Predecessor’s deferred financing costs were eliminated through the application of pushdown accounting resulting in no amortization for the Successor period.

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

The factors impacting operating income are discussed in the business segment results.

Interest expense. Interest expense increased from $3.2 million for the year ended December 31, 2015 to $3.9 million for the year ended December 31, 2016, an increase of $0.8 million. For the year ended December 31, 2015, we incurred interest expense of $2.4 million in connection with our revolving credit facility and the Water Assets were allocated $0.8 million of interest expense by Rice Energy. For the year ended December 31, 2016, the full amount of interest expense incurred related to

borrowing under our revolving credit facility. Our average borrowing under our revolving credit facility for the years ended December 31, 2016 and 2015 was $110.0 million and $46.9 million, respectively.

Amortization of deferred financing costs. Amortization of deferred financing costs increased from $0.6 million for the year ended December 31, 2015 to $1.5 million for the year ended December 31, 2016, an increase of $0.9 million , or 157%. The increase primarily related to the timing of financing costs incurred associated with equity offerings and amendments to our revolving credit facility.

Income tax expense. The $5.8 million income tax expense for the year ended December 31, 2015 was allocated to the Water Assets prior to their acquisition by Rice Energy. Following our initial public offering, we are not subject to U.S. federal income tax and certain state income taxes due to our status as a partnership.

Business Segment Results of Operations

We operate in two business segments: (i) gathering and compression and (ii) water services. The gathering and compression segment provides natural gas gathering and compression services for EQT and third parties in the Appalachian Basin. The water services segment is engaged in the provision of water services to support well completion activities and to collect and recycle or dispose of flowback and produced water for EQT and third parties in the Appalachian Basin.

We evaluate our business segments on their contribution to our consolidated results based on operating income. Please see Note 10 to the Consolidated Financial Statements included in the Annual Report for a reconciliation of each segment’s operating income to our consolidated operating income.

The following tables set forth selected segment financial data and certain operating data for the Combined Year ended December 31, 2017 compared to the year ended December 31, 2016 and for the year ended December 31, 2016 compared to the year ended December 31, 2015 :

Gathering and Compression Segment



	Successor		Predecessor		(Unaudited) Combined Year		Predecessor					Predecessor
Financial data: (in thousands)	Period from November 13, 2017 to December 31, 2017		Period from January 1, 2017 to November 12, 2017		Year Ended December 31, 2017		Year Ended December 31, 2016					Year Ended December 31, 2015		Change
Financial data: (in thousands)	Period from November 13, 2017 to December 31, 2017		Period from January 1, 2017 to November 12, 2017		Year Ended December 31, 2017		Year Ended December 31, 2016		Change			Year Ended December 31, 2015		Change
Gathering revenues:
Affiliate	$	26,242	$	110,594	$	136,836	$	77,625	$	59,211		$	59,734	$	17,891
Third-party	19		34,136		34,155		38,669		(4,514		)	15,980		22,689
Total gathering revenues	26,261		144,730		170,991		116,294		54,697			75,714		40,580

Compression revenues:
Affiliate	4,343		16,031		20,374		8,722		11,652			1,445		7,277
Third-party	10		6,731		6,741		7,083		(342		)	52		7,031
Total compression revenues	4,353		22,762		27,115		15,805		11,310			1,497		14,308
Total operating revenues	30,614		167,492		198,106		132,099		66,007			77,211		54,888

Operating expenses:
Operation and maintenance expense	1,584		11,939		13,523		8,000		5,523			6,006		1,994
General and administrative expense	3,265		18,944		22,209		17,301		4,908			13,886		3,415
Depreciation expense	3,965		11,324		15,289		10,840		4,449			6,310		4,530
Acquisition costs	—		529		529		125		404			—		125
Amortization of intangible assets	—		1,413		1,413		1,634		(221		)	1,632		2
Other expense	—		2,594		2,594		1,051		1,543			492		559
Total operating expenses	8,814		46,743		55,557		38,951		16,606			28,326		10,625

Operating income	$	21,800	$	120,749	$	142,549	$	93,148	$	49,401		$	48,885	$	44,263

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

Operating revenues. Revenues from gathering and compression of natural gas increased from $132.1 million for the year ended December 31, 2016 to $198.1 million for the Combined Year ended December 31, 2017 , an increase of $66.0 million , or 50% . The increase in operating revenues primarily relates to increased gathering and compression revenues associated with a

43% and 67% increase in period over period gathering and compression throughput, respectively. Post-acquisition gathering and compression revenues from the Vantage Midstream Entities increased from $6.3 million for the year ended December 31, 2016 to $46.5 million for the Combined Year ended December 31, 2017 .



	Year Ended December 31,		Change	%
Operating data:	2017	2016	Change	%
Gathering volumes: (in BBtu/d)
Total gathering volumes	1,405	983	422	43	%



	Year Ended December 31,		Change	%
Operating data:	2017	2016	Change	%
Compression volumes: (in BBtu/d)
Total compression volumes	958	572	386	67	%

Operation and maintenance expense. Total operation and maintenance expense increased from $8.0 million for the year ended December 31, 2016 to $13.5 million for the Combined Year ended December 31, 2017 , an increase of $5.5 million , or 69% . The increase year-over-year was primarily due to increases in line maintenance expenses and compressor rental charges associated with compressor stations acquired in connection with the Vantage Midstream Asset Acquisition.

General and administrative expense . General and administrative expense increased from $17.3 million for the year ended December 31, 2016 to $22.2 million for the Combined Year ended December 31, 2017 , an increase of $4.9 million , or 28% . The increase year-over-year was primarily due to an increase in allocated costs associated with personnel and administrative expenses consistent with the growth of the business.

Depreciation expense . Depreciation expense increased from $10.8 million for the year ended December 31, 2016 to $15.3 million for the Combined Year ended December 31, 2017 , an increase of $4.4 million , or 41% . The increase year-over-year was primarily due to additional gathering and compression assets placed into service in 2017. For the Combined Year ended December 31, 2017, our gathering pipeline miles increased 12%.

Amortization of intangible assets. In the Predecessor period, the Partnership’s intangible assets were primarily comprised of customer contracts with EQT that were acquired as part of an April 2014 acquisition of certain gas gathering assets in Washington and Greene Counties, Pennsylvania. The customer contracts were assigned a useful life of 30 years and amortized on a straight-line basis. At the Merger Date, the Predecessor’s intangible assets related to customer contracts with EQT were eliminated through the application of pushdown accounting.

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

Operating revenues. Revenues from gathering and compression of natural gas increased from $77.2 million for the year ended December 31, 2015 to $132.1 million for the year ended December 31, 2016, an increase of $54.9 million, or 71%. The increase in operating revenues primarily relates to increased gathering and compression revenues associated with a 52% and 794% increase in year-over-year gathering and compression throughput, respectively.



	Year Ended December 31,		Change	%
Operating data:	2016	2015	Change	%
Gathering volumes: (in BBtu/d)
Total gathering volumes	983	647	336	52	%



	Year Ended December 31,		Change	%
Operating data:	2016	2015	Change	%
Compression volumes: (in BBtu/d)
Total compression volumes	572	64	508	794	%

Operation and maintenance expense. Total operation and maintenance expense increased from $6.0 million for the year ended December 31, 2015 to $8.0 million for the year ended December 31, 2016, an increase of $2.0 million, or 33%. The increase year-over-year was primarily due to an increase in contract labor expenses and subsidence repair costs.

General and administrative expense. General and administrative expense increased from $13.9 million for the year ended December 31, 2015 to $17.3 million for the year ended December 31, 2016, an increase of $3.4 million , or 24%. The increase year-over-year was primarily due to an increase in allocated costs associated with personnel and administrative expenses as we continue to grow. Included in general and administrative expense is equity compensation expense of $2.3 million and $3.9 million for the years ended December 31, 2016 and December 31, 2015, respectively.

Depreciation expense. Depreciation expense increased from $6.3 million for the year ended December 31, 2015 to $10.8 million for the year ended December 31, 2016, an increase of $4.5 million, or 71%. The increase year-over-year was primarily due to additional gathering and compression assets placed into service in 2016. For the year ended December 31, 2016, our gathering pipeline miles increased 40%.

Water Services Segment



	Successor		Predecessor		(Unaudited) Combined Year		Predecessor					Predecessor
Financial data: (in thousands)	Period from November 13, 2017 to December 31, 2017		Period from January 1, 2017 to November 12, 2017		Year Ended December 31, 2017		Year Ended December 31, 2016					Year Ended December 31, 2015		Change
Financial data: (in thousands)	Period from November 13, 2017 to December 31, 2017		Period from January 1, 2017 to November 12, 2017		Year Ended December 31, 2017		Year Ended December 31, 2016		Change			Year Ended December 31, 2015		Change
Operating revenues:
Affiliate	$	13,549	$	77,017	$	90,566	$	65,913	$	24,653		$	32,488	$	33,425
Third-party	56		5,965		6,021		3,611		2,410			4,760		(1,149		)
Total operating revenues	13,605		82,982		96,587		69,524		27,063			37,248		32,276

Operating expenses:
Operation and maintenance expense	$	5,598	$	21,829	$	27,427	$	16,608	$	10,819		$	8,904	$	7,704
General and administrative expense	347		3,308		3,655		4,312		(657		)	4,009		303
Incentive unit expense	—		—		—		—		—			1,044		(1,044		)
Depreciation expense	3,515		15,096		18,611		14,330		4,281			10,089		4,241
Amortization of intangible assets	—		—		—		—		—			—		—
Other expense	—		20		20		480		(460		)	51		429
Total operating expenses	9,460		40,253		49,713		35,730		13,983			24,097		11,633

Operating income	$	4,145	$	42,729	$	46,874	$	33,794	$	13,080		$	13,151	$	20,643

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

Operating revenues . Operating revenues increased from $69.5 million for the year ended December 31, 2016 to $96.6 million for the Combined Year ended December 31, 2017 . The $27.1 million , or 39% increase in operating revenues year-over-year primarily relates a 46% increase in water service volumes associated with our water service agreements with EQT and third parties. Post-acquisition water services revenues from the Vantage Midstream Entities increased from $2.3 million for the year ended December 31, 2016 to $11.2 million for the Combined Year ended December 31, 2017 .



Operating data:	Year Ended December 31,			%
Water services volumes: (in MMgal)	2017	2016	Change	%
Total water services volumes	1,833	1,253	580	46	%

Operation and maintenance expense . Total operation and maintenance expense increased from $16.6 million for the year ended December 31, 2016 to $27.4 million for the Combined Year ended December 31, 2017 , an increase of $10.8 million , or 65% . The increase was primarily due to an increase in variable water costs associated with the need for supplemental systems to support EQT’s hydraulic fracturing operations.

Depreciation expense . Depreciation expense increased from $14.3 million for the year ended December 31, 2016 to $18.6 million for the Combined Year ended December 31, 2017 , an increase of $4.3 million , or 30% . The increase year-over-year was primarily due to additional water handling and treatment assets placed into service in 2017. For the Combined Year ended December 31, 2017, our water pipeline miles increased 6% .

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

Operating revenues. Operating revenues increased from $37.2 million for the year ended December 31, 2015 to $69.5 million for the year ended December 31, 2016. The $32.3 million increase in operating revenues year-over-year primarily relates a 61% increase in water service volumes associated with our water service agreements with Rice Energy and third parties.



Operating data:	Year Ended December 31,		Change	%
Water services volumes: (in MMgal)	2016	2015	Change	%
Total water services volumes	1,253	777	476	61	%

Operation and maintenance expense. Total operation and maintenance expense increased from $8.9 million for the year ended December 31, 2015 to $16.6 million for the year ended December 31, 2016, an increase of $7.7 million. The increase was primarily due to on and off pad water transfer costs and water procurement, in addition to increased expenses following the Vantage Midstream Asset Acquisition primarily associated with water transfer costs and pipeline maintenance costs.

Incentive unit expense. Incentive unit expense for the year ended December 31, 2015 was $1.0 million. These costs were allocated to the water services segment by Rice Energy prior to the acquisition of the Water Assets. No incentive unit expense was incurred for the year ended December 31, 2016.

Depreciation expense. Depreciation expense increased from $10.1 million for the year ended December 31, 2015 to $14.3 million for the year ended December 31, 2016, an increase of $4.2 million, or 42%. The increase year-over-year was primarily due to additional water handling and treatment assets placed into service in 2016. For the year ended December 31, 2016, our water pipeline miles increased 15%.

Non-GAAP Financial Measures

Adjusted EBITDA

We define our adjusted EBITDA (Adjusted EBITDA) as net income before interest expense, income tax expense, depreciation expense, acquisition costs, amortization of intangible assets, non-cash equity compensation expense, incentive unit expense, amortization of deferred financing costs and certain other items management believes affect the comparability of our operating results. Adjusted EBITDA is a non-GAAP supplemental financial measure.

Distributable cash flow

We define distributable cash flow as Adjusted EBITDA less cash interest expense, and estimated maintenance capital expenditures. Distributable cash flow does not reflect changes in working capital balances. Distributable cash flow is a non-GAAP supplemental financial measure that does not reflect changes in our working capital.

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


•	the financial performance of our assets, without regard to financing methods, capital structure or historical cost basis;


•	our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to historical cost basis or, in the case of Adjusted EBITDA, financing or capital structure;


•	our ability to incur and service debt and fund capital expenditures;


•	the ability of our assets to generate sufficient cash flow to make distributions to our unitholders; and


•	the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that Adjusted EBITDA and distributable cash flow provide useful information to investors in assessing our financial condition and results of operations. Adjusted EBITDA and distributable cash flow should not be considered as alternatives to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and distributable cash flow have important limitations as analytical tools because they exclude some, but not all, items that affect net income and net cash provided by operating activities. Additionally, because Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled

measures of other companies, thereby diminishing the utility of the measures. Distributable cash flow should not be viewed as indicative of the actual amount of cash that we have available for distributions from operating surplus or that we plan to distribute.

The following table presents a reconciliation of the non-GAAP financial measures of Adjusted EBITDA and distributable cash flow to the most directly comparable GAAP financial measures of net income and net cash provided by operating activities.



	Successor			Predecessor
	Period from November 13, 2017 to December 31, 2017			Period from January 1, 2017 to November 12, 2017			Year ended December 31,
(in thousands)	Period from November 13, 2017 to December 31, 2017			Period from January 1, 2017 to November 12, 2017			2016 ⁽²⁾			2015
Adjusted EBITDA reconciliation to Net income:
Net income	$	25,134		$	152,839		$	121,610		$	52,495
Interest expense	826			7,053			3,931			3,164
Income tax expense	—			—			—			5,812
Depreciation expense	7,480			26,420			25,170			16,399
Acquisition costs	—			529			125			—
Amortization of intangible assets	—			1,413			1,634			1,632
Non-cash equity compensation expense	17			497			2,873			4,501
Incentive unit expense	—			—			—			1,044
Amortization of deferred financing costs	—			3,642			1,479			576
Other expense	—			2,614			1,531			543
Adjusted EBITDA attributable to Water Assets prior to acquisition ⁽¹⁾	—			—			—			(22,386		)
Adjusted EBITDA	$	33,457		$	195,007		$	158,353		$	63,780
Less:
Cash interest expense	(826		)	(7,053		)	(3,931		)	(2,356		)
Estimated maintenance capital expenditures	(2,397		)	(15,103		)	(11,200		)	(4,480		)
Distributable cash flow	$	30,234		$	172,851		$	143,222		$	56,944

Reconciliation of net cash provided by operating activities to distributable cash flow:
Net cash provided by operating activities	$	22,430		$	150,811		$	154,117		$	70,006
Interest expense	826			7,053			3,931			3,164
Acquisition costs	—			529			125			—
Cash interest expense	(826		)	(7,053		)	(3,931		)	(2,356		)
Estimated maintenance capital expenditures	(2,397		)	(15,103		)	(11,200		)	(4,480		)
Other expense	—			2,614			1,531			543
Changes in operating assets and liabilities which provided (used) cash	10,201			34,000			(1,351		)	12,453
Adjusted EBITDA attributable to Water Assets prior to acquisition ⁽¹⁾	—			—			—			(22,386		)
Distributable cash flow	$	30,234		$	172,851		$	143,222		$	56,944

(1)

Adjusted EBITDA attributable to the Water Assets prior to their acquisition is excluded from our Adjusted EBITDA calculation as these amounts were generated by Rice Energy prior to the acquisition and are not attributable to our limited partners. Adjusted EBITDA attributable to the Water Assets prior to the acquisition for the year ended December 31, 2015 was calculated as net income of $7.3 million plus depreciation expense of $7 million, income tax expense of $5.8 million, incentive unit expense of $1.1 million and other charges of $1.2 million.


(2)	Includes post-acquisition results of the Vantage Midstream Entities. Please see Note 2 to the Consolidated Financial Statements included in this Annual Report for further detail regarding the Vantage Midstream Asset Acquisition.

Outlook

Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing growth of our business. We believe that we are positioned to achieve growth based on the low

development cost, consistently high production volumes and access to multiple takeaway pipelines of the Marcellus Shale. Our assets are sized to accommodate projected future production growth of EQT and third parties in our areas of operation. However, our ability to grow depends, in part, on our ability to make acquisitions or attract additional volumes that increase our cash generated from operations on a per unit basis. Prior to the Mergers, the acquisition component of our strategy was based, in large part, on our ability to acquire midstream energy assets from industry participants, including Rice Energy. In that regard, EQT has publicly announced its intention to sell Rice Energy’s retained midstream assets acquired by EQT in connection with the Mergers to EQM. Furthermore, EQT’s relationship with EQM and EQGP or a transfer of the incentive distribution rights in us held by EQT could otherwise impair our access to future midstream assets and/or organic growth projects and the willingness of EQT to offer us acquisition opportunities in the future.

Our 2018 capital expenditure forecast is $260 million , including $215 million for gathering and compression and $45 million for water infrastructure. See further discussion of capital expenditures in the “Capital Resources and Liquidity” section below.

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

Capital Resources and Liquidity

Sources and Uses of Cash

Our principal liquidity requirements are to finance our operations, fund capital expenditures, make cash distributions and satisfy any indebtedness obligations. Our ability to meet these liquidity requirements will depend on our ability to generate cash in the future as well as our ability to raise capital in banking, capital and/or other markets. Our available sources of liquidity include cash generated from operations, borrowing under our revolving credit facility, cash on hand, debt offerings and issuances of additional RMP partnership units. We expect the combination of these resources will be adequate to fund our short-term working capital requirements, long-term capital expenditures program and expected quarterly distributions, including IDRs.

Cash Flow Provided by Operating Activities

Net cash provided by operating activities was $173.2 million for the Combined Year ended December 31, 2017 and $154.1 million and $70.0 million for the years ended December 31, 2016 and 2015 , respectively. The increase in operating cash flow for all periods was driven by higher operating income for which contributing factors are discussed in the “Results of Operations” section herein and the timing of payments between periods.

Cash Flow Used in Investing Activities

During the Combined Year ended December 31, 2017 , we used cash flows in investing activities totaling $166.0 million primarily to fund the continued build-out of our gathering and water systems. During the year ended December 31, 2016 , we used cash flows in investing activities totaling $721.1 million primarily to fund the Vantage Midstream Asset Acquisition and capital expenditures for the development of our gathering and compression and water systems. During the year ended December 31, 2015 , we used cash flows in investing activities totaling $380.0 million primarily to fund capital expenditures for the development of our gathering systems and the acquisition of the Water Assets.

Capital expenditures for the gathering and compression segment were $141.7 million , $113.0 million and $149.7 million for the Combined Year ended December 31, 2017 and for the years ended December 31, 2016 and 2015 , respectively. The increase year-over-year from 2016 to the Combined Year 2017 was attributable to the continued build-out of our gathering system. The decrease year-over-year from 2015 to 2016 was attributable to a greater focus on capital expenditures for compression stations and well pad connects rather than the build out of our gathering system.

Capital expenditures for the water services segment were $16.6 million , $8.1 million and $98.8 million for the Combined Year ended December 31, 2017 and for the years ended December 31, 2016 and 2015 , respectively. The increase year-over-year from 2016 to the Combined Year 2017 was primarily due to the continued build-out of our water services business. The decrease year-over-year from 2015 to 2016 was primarily the result of the substantial majority of our water service assets being built in the prior year.

Cash Flow (Used in) Provided by Financing Activities

Net cash used in financing activities for the Combined Year ended December 31, 2017 of $18.6 million was primarily associated with quarterly distributions to our public unitholders and GP Holdings, partially offset by borrowings under our

revolving credit facility. Net cash provided by financing activities for the year ended December 31, 2016 of $581.2 million was primarily composed of net proceeds from our offering of common units in June 2016 and net proceeds from borrowings under our revolving credit facility which was partially offset by distributions to our unitholders. Net cash provided by financing activities for the year ended December 31, 2015 of $290.7 million was primarily the result of net proceeds from common unit issuances, net borrowings under our revolving credit facility and contributions from Rice Energy related to the Water Assets prior to their acquisition, which was partially offset by the excess of the purchase price of the Water Assets from Rice Energy and distributions to our unitholders.

Capital Requirements

The midstream business is capital intensive, requiring significant investment for the maintenance of existing assets and the development of new systems and facilities. We categorize our capital expenditures as either:

•

Expansion capital expenditures : Expansion capital expenditures are cash expenditures to construct new midstream infrastructure and those expenditures incurred in order to extend the useful lives of our assets, reduce costs, increase revenues or increase system capacity from current levels, including well connections that increase existing volumes. Examples of expansion capital expenditures include the construction, development or acquisition of additional gas gathering and water pipelines, compressor stations, pumping stations and impoundment facilities, in each case to the extent such capital expenditures are expected to expand our capacity or our operating income. In the future, if we make acquisitions that increase system throughput or capacity or our operating income, the associated capital expenditures may also be considered expansion capital expenditures.

•

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

For the year ending December 31, 2018, we plan to invest $260 million , $215 million on gathering and compression infrastructure and $45 million on water infrastructure. Estimated maintenance capital expenditures for the year ending December 31, 2018 reflect management’s judgment of the amount of capital that will be needed annually to maintain, over the long term, the operating capacity and operating income of our assets. The types of maintenance capital expenditures that we expect to incur include expenditures to connect additional wells to maintain current volumes and expenditures to replace system components and equipment that have suffered significant wear and tear or become obsolete. Our natural gas gathering and water distribution systems have been recently constructed, and as a result we anticipate that they will require minimal levels of capital expenditures to repair wear and tear and sustain their current level of operation. The expansion capital expenditures estimated to be spent during the year ending December 31, 2018 are related to projects that will increase our long-term operating capacity and operating income and position us to capitalize on the growth opportunities we anticipate impacting our areas of operation in the near-term.

Our future expansion capital expenditures may vary significantly from period to period based on the investment opportunities available to us.

Debt Agreements and Contractual Obligations

Please see Note 3 to the Consolidated Financial Statements included in this Annual Report for information related to debt agreements.

Contractual Obligations . A summary of our contractual obligations as of December 31, 2017 is provided in the following table.



	Payments due by period For the Year Ending December 31,
(in thousands)	2018		2019		2020		2021		2022		Thereafter		Total
Revolving credit facility	$	—	$	286,000	$	—	$	—	$	—	$	—	$	286,000
Water infrastructure	—		—		—		—		—		19,547		19,547
Purchase Obligations	7,031		—		—		—		—		—		7,031
Operating lease obligations	1,164		1,164		606		323		323		—		3,580
Total	$	8,851	$	287,164	$	606	$	323	$	323	$	32,013	$	329,280

At the Market Program

As of February 15, 2018, we had approximately $83.7 million in remaining capacity under the ATM Program (as defined in Note 5 to the Consolidated Financial Statements included in this Annual Report).

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported if different assumptions had been used or that actual results may differ materially from our estimates. We evaluate these estimates and assumptions on a regular basis. The following critical accounting policies, which were reviewed by the Audit Committee of the Board of Directors of our general partner, relate to our more significant judgments and estimates used in the preparation of our consolidated financial statements. Please read Note 1 to the Consolidated Financial Statements included in this Annual Report for a discussion of our significant accounting policies.

Property and Equipment

We capitalize construction-related direct labor and material costs. Maintenance and repair costs are expensed as incurred. Determination of depreciation expense requires judgment regarding the estimated useful lives and salvage values of property and equipment. We have not historically experienced material changes in our results of operations from changes in the estimated useful lives or salvage values of property and equipment although these estimates are reviewed periodically. However, in conjunction with the Mergers and the application of pushdown accounting, changes were made to the estimated useful lives. We believe that the accounting estimates related to depreciation expense are "critical accounting estimates" because they are susceptible to change period to period. These assumptions affect the amount of depreciation and operating expense and would have an impact on the results of operations if changed.

Impairments

Any accounting estimate related to impairment of property and equipment requires our management to make assumptions about future cash flows, discount rates and the estimated price between market participants to sell an asset in the principal market for the asset. 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. We historically have not had indicators of impairment. However, we believe that the accounting estimates related to impairments are "critical accounting estimates" because they require assumptions that are susceptible to change period to period. Any potential impairment would have an impact on our results of operations and financial position.

General and Administrative Costs

General and administrative and operating and maintenance costs are allocated to EQT’s business units, including our segments, based upon the nature of the expenses. Costs that are directly related to us are directly charged to us. Other costs are allocated based on operational and financial metrics. Allocations are based on estimates and assumptions that management believes are reasonable; however, we believe that the accounting estimates related to allocated costs are "critical accounting estimates" because different estimates and assumptions would change the amounts allocated to us and those differences could be material. These assumptions affect the amount of general and administrative and operating expense and would have an impact on the results of operations if changed.

Contingencies

We are involved in various regulatory and legal proceedings that arise in the ordinary course of business. A liability is recorded for contingencies based upon our assessment that a loss is probable and that the amount of the loss can be reasonably estimated. We consider many factors in making these assessments, including the history and specifics of each matter. Estimates are developed in consultation with legal counsel and are based upon an analysis of potential results. We believe that the accounting estimates related to contingencies are “critical accounting estimates” because management must assess the probability and amount of loss related to contingencies. Future results of operations could be materially affected by changes in the assumptions or by results that differ from our current expectations.

Business Combinations and Pushdown Accounting

We account for acquisitions using the purchase method of accounting. Accordingly, assets acquired and liabilities assumed are recorded at their estimated fair values at the acquisition date. The excess of purchase price over fair value of net assets acquired, including the estimated fair value of identifiable intangible assets, if any, is recorded as goodwill. Given the time it takes to obtain pertinent information to finalize the allocation of the purchase price to the acquired net assets, the purchase price allocation may remain preliminary for a period of time before we are able to finalize the required fair value estimates. Accordingly, it is not uncommon for the initial estimates to be subsequently revised. We have applied pushdown accounting in our consolidated financial statements related to EQT’s acquisition of our general partner based on the preliminary purchase price allocation completed by EQT. We believe that the accounting estimates related to business combinations and pushdown accounting are “critical accounting estimates” because EQT has yet to finalize its allocation of the purchase price for its acquisition of Rice Energy, which includes significant assumptions that could materially impact the purchase price allocation and pushdown accounting to us. Subsequent changes to the purchase price allocation for EQT’s acquisition of Rice Energy could have a material impact on our consolidated financial statements.

Goodwill

At December 31, 2017 , we had goodwill, recorded as a result of pushdown accounting, totaling $1.3 billion . Goodwill is subject to periodic assessment for impairment at the reporting unit level. We perform an annual goodwill impairment assessment in the fourth quarter unless qualitative facts and circumstances exist that indicate a triggering event which would warrant an interim assessment. We use a combination of the income and market approach to estimate the fair value of a reporting unit. The fair value estimation process requires considerable judgment and determining the fair value is sensitive to changes in assumptions impacting management’s estimates of future financial results as well as other assumptions such as weighted-average cost of capital, terminal growth rates and industry multiples. Although we believe the estimates and assumptions used in estimating the fair value are reasonable and appropriate, different estimates and assumptions could materially impact the calculated fair value of the reporting units. Additionally, future results could differ from our current estimates and assumptions. We believe that the estimates and assumptions used in determining the estimated fair value of a reporting unit are "critical accounting estimates" because they require assumptions that are susceptible to change period to period. Any potential change in such estimates and assumptions would have an impact on the results of operations and financial position.

Recently Issued Accounting Pronouncements

Please see Note 1 to the Consolidated Financial Statements included in this Annual Report for further discussion of recently issued accounting pronouncements.

Off-Balance Sheet Arrangements

Currently, we do not have any off-balance sheet arrangements as defined by the SEC. In the ordinary course of business, we enter into various commitment agreements and other contractual obligations, some of which are not recognized in our consolidated financial statements in accordance with GAAP.

Commitments and Contingencies

Please see Note 4 to the Consolidated Financial Statements included in this Annual Report for a description of our commitments and contingencies.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.

Commodity Price Risk

Our gas agreements with EQT provide for volume based fixed price per unit structures. To the extent that our future contractual arrangements with EQT or third parties do not provide for fixed price per unit structures, we may become subject to commodity price risk. As we do not take ownership of the natural gas we gather, we generally do not have direct exposure to fluctuations in commodity prices. However, our business is dependent on the continued availability of natural gas production and reserves in our areas of operation. Low prices for natural gas, including those resulting from regional basis differentials, could adversely affect development of additional reserves and production that is accessible by our gathering and water assets. Lower regional 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. EQT, or third-party customers on our systems, may reduce capital spending in the future based on commodity prices or other factors. Unless we are successful in attracting and retaining unaffiliated third-party customers, our ability to maintain or increase the gathering and water services volumes on our systems will be dependent on receiving consistent or increasing commitments from EQT. While EQT has dedicated acreage to us under long-term contracts, EQT may determine in the future that drilling in our areas of operations is not economical or that drilling in areas outside of our current areas of operations, including areas serviced by EQM, is strategically more attractive to it. EQT is under no contractual obligation to continue to develop its acreage dedicated to us. Please read “Risks Related to Our Business—Our exposure to commodity price risk may change over time.” in “Item 1A. Risk Factors.”

Interest Rate Risk

Our primary interest rate risk exposure results from our revolving credit facility, which has a floating interest rate. The average annual interest rate incurred on our revolving credit facility during the year ended December 31, 2017 was approximately 3.1% . A 1.0% increase in each of the applicable average interest rates during the year ended December 31, 2017 would have resulted in a $2.0 million estimated increase in interest expense for that period.

As of December 31, 2017 , we did not have any derivatives in place to mitigate the effects of interest rate risk. We may implement an interest rate hedging strategy in the future.

Please see Note 3 to the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional information.

Credit Risk

For the year ended December 31, 2017, EQT (inclusive of the combined results of Rice Energy) represented substantially all of our gathering and compression revenues and 96% of our water services revenues. We are dependent on EQT as our most significant customer, and we expect to derive a substantial majority of our revenues from EQT for the foreseeable future. As a result, any event, whether in our dedicated areas or otherwise, that adversely affects EQT’s production, drilling schedule, financial condition, leverage, market reputation, liquidity, results of operations or cash flows may adversely affect our revenues and cash available for distribution.

Further, we are subject to the risk of non-payment or non-performance by EQT, including with respect to our gathering and water services agreements. We cannot predict the extent to which EQT’s business would be impacted if conditions in the energy industry were to deteriorate, nor can we estimate the impact such conditions would have on EQT’s ability to execute its drilling and development program or to perform under our agreements with EQT. As of December 31, 2017, EQT’s public senior debt had an investment grade credit rating. Any material non-payment or non-performance by EQT could reduce our ability to make distributions to our unitholders. Please read “Risks Related to Our Business—Because a substantial majority of our revenue currently is, and over the long term is expected to be, derived from EQT, any development that materially and adversely affects EQT’s operations, financial condition or market reputation could have a material and adverse impact on us.” in “Item 1A. Risk Factors.”

We manage credit risk of sales to third parties by limiting dealings to those third parties meeting specified criteria for credit and liquidity strength and by actively monitoring these accounts. We may request a letter of credit, guarantee,

performance bond or other credit enhancement from a third party in order for that third party to meet our credit criteria. We did not experience any significant defaults on accounts receivable for the years ended December 31, 2017 , 2016 and 2015 .

Item 8. Financial Statements and Supplementary Data



	Page
Rice Midstream Partners
Reports of Independent Registered Public Accounting Firm	58
Consolidated Balance Sheets as of December 31, 2017 and 2016	60
Consolidated Statements of Operations for the Period from Acquisition (November 13, 2017) to December 31, 2017, Period from January 1, 2017 to November 12, 2017 and the Years Ended December 31, 2016 and 2015	61
Consolidated Statements of Cash Flows for the Period from Acquisition (November 13, 2017) to December 31, 2017, Period from January 1, 2017 to November 12, 2017 and the Years Ended December 31, 2016 and 2015	63
Consolidated Statements of Partners’ Capital for the Period from Acquisition (November 13, 2017) to December 31, 2017, Period from January 1, 2017 to November 12, 2017 and the Years Ended December 31, 2016 and 2015	65
Notes to Consolidated Financial Statements	66

Report of Independent Registered Public Accounting Firm

To the Unitholders of Rice Midstream Partners LP and the Board of Directors of Rice Midstream Management LLC

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Rice Midstream Partners LP (the Partnership) as of December 31, 2017 (Successor) and 2016 (Predecessor), and the related consolidated statements of operations, cash flows, and partners’ capital for the period from November 13, 2017 through December 31, 2017 (Successor), the period from January 1, 2017 through November 12, 2017 (Predecessor) and the years ended December 31, 2016 and 2015 (Predecessor) and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the consolidated financial position of the Partnership at December 31, 2017 (Successor) and 2016 (Predecessor), and the consolidated results of its operations and its cash flows for the period from November 13, 2017 through December 31, 2017 (Successor), the period from January 1, 2017 through November 12, 2017 (Predecessor) and the years ended December 31, 2016 and 2015 (Predecessor), in conformity with U.S. generally accepted accounting principles.

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

Basis for Opinion

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

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

/s/ Ernst & Young LLP

We have served as the Partnership’s auditor since 2014.

Pittsburgh, Pennsylvania

February 15, 2018

Report of Independent Registered Public Accounting Firm

To the Unitholders of Rice Midstream Partners LP and the Board of Directors of Rice Midstream Management LLC

Opinion on Internal Control over Financial Reporting

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

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of Rice Midstream Partners LP as of December 31, 2017 (Successor) and 2016 (Predecessor), and the related consolidated statements of operations, cash flows, and partners’ capital for the period from November 13, 2017 through December 31, 2017 (Successor), the period from January 1, 2017 through November 12, 2017 (Predecessor) and the years ended December 31, 2016 and 2015 (Predecessor) and the related notes of the Partnership and our report dated February 15, 2018 expressed an unqualified opinion thereon.

Basis for Opinion

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

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

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

Definition and Limitations of Internal Control Over Financial Reporting

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

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

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

February 15, 2018

Rice Midstream Partners LP

Consolidated Balance Sheets



	Successor		Predecessor
(in thousands)	December 31, 2017		December 31, 2016
Assets
Current assets:
Cash	$	10,538	$	21,834
Accounts receivable	12,246		8,758
Accounts receivable - affiliate	46,182		11,838
Prepaid expenses, deposits and other	1,327		64
Total current assets	70,293		42,494

Property and equipment, net	1,431,802		805,027
Deferred financing costs, net	—		12,591
Goodwill	1,346,918		494,580
Other assets	—		44,525
Total assets	$	2,849,013	$	1,399,217

Liabilities and partners’ capital
Current liabilities:
Accounts payable	4		4,172
Accrued capital expenditures	24,630		9,074
Other accrued liabilities	4,200		8,376
Total current liabilities	28,834		21,622

Long-term liabilities:
Revolving credit facility	286,000		190,000
Other long-term liabilities	9,360		5,189
Total liabilities	324,194		216,811

Partners’ capital:
Parent net equity	—		—
Common units (73,549,485 and 73,519,133 issued and outstanding at December 31, 2017 and 2016, respectively)	1,566,625		1,275,935
Subordinated units (28,753,623 issued and outstanding at December 31, 2017 and 2016)	612,454		(94,417		)
General Partner	345,740		888
Total partners’ capital	2,524,819		1,182,406
Total liabilities and partners’ capital	$	2,849,013	$	1,399,217

The accompanying notes are an integral part of these Consolidated Financial Statements.

Rice Midstream Partners LP

Consolidated Statements of Operations



	Successor			Predecessor
	Period from November 13, 2017 to December 31, 2017			Period from January 1, 2017 to November 12, 2017			Years Ended December 31,
(in thousands, except per unit data)	Period from November 13, 2017 to December 31, 2017			Period from January 1, 2017 to November 12, 2017			2016			2015
Operating revenues:
Affiliate	$	44,134		$	203,642		$	152,260		$	93,668
Third-party	85			46,832			49,363			20,791
Total operating revenues	44,219			250,474			201,623			114,459

Operating expenses:
Operation and maintenance expense	7,182			33,768			24,608			14,910
General and administrative expense ⁽¹⁾	3,612			22,252			21,613			17,895
Incentive unit expense ⁽²⁾	—			—			—			1,044
Depreciation expense	7,480			26,420			25,170			16,399
Acquisition costs	—			529			125			—
Amortization of intangible assets	—			1,413			1,634			1,632
Other expense	—			2,614			1,531			543
Total operating expenses	18,274			86,996			74,681			52,423

Operating income	25,945			163,478			126,942			62,036
Other income	15			56			78			11
Interest expense ⁽³⁾	(826		)	(7,053		)	(3,931		)	(3,164		)
Amortization of deferred finance costs	—			(3,642		)	(1,479		)	(576		)
Income before income taxes	25,134			152,839			121,610			58,307
Income tax expense	—			—			—			(5,812		)
Net income	$	25,134		$	152,839		$	121,610		$	52,495

Calculation of limited partner interest in net income:
Net income	$	25,134		$	152,839		$	121,610		$	52,495
Less: Pre-acquisition net income allocated to general partner	—			—			—			7,296
Less: General partner interest in net income attributable to incentive distribution rights	1,599			6,182			1,428			—
Limited partner net income	$	23,535		$	146,657		$	120,182		$	45,199

Net income per limited partner: ⁽⁴⁾
Common units (basic)	$	0.23		$	1.43		$	1.46		$	0.76
Common units (diluted)	$	0.23		$	1.43		$	1.45		$	0.76
Subordinated units	$	0.23		$	1.43		$	1.50		$	0.76


(1)	In the Successor period, general and administrative expenses include charges from EQT of $2.9 million . For the Predecessor period from January 1, 2017 to November 12, 2017, and for the years ended December 31, 2016 and 2015, $19.4 million , $16.6 million and $11.9 million of general and administrative expenses include charges from Rice Energy Inc. (Rice Energy), respectively.


(2)	Incentive unit expense for the year ended December 31, 2015 was allocated from Rice Energy.


(3)	Interest expense includes charges from Rice Energy of $0.8 million for the year ended December 31, 2015 .


(4)	Net income per limited partner unit does not include results attributable to the Pennsylvania and Ohio fresh water services assets (Water Assets) prior to their acquisition as those results are not attributable to limited partners of the Partnership.

The accompanying notes are an integral part of these Consolidated Financial Statements.

Rice Midstream Partners LP

Consolidated Statements of Cash Flows



	Successor			Predecessor
	Period from November 13, 2017 to December 31, 2017			Period from January 1, 2017 to November 12, 2017			Years Ended December 31,
(in thousands)							2016			2015
Cash flows from operating activities:
Net income	$	25,134		$	152,839		$	121,610		$	52,495
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation expense	7,480			26,420			25,170			16,399
Amortization of intangibles	—			1,413			1,634			1,632
Amortization of deferred finance costs	—			3,642			1,479			576
Incentive unit expense	—			—			—			1,044
Equity compensation expense	17			497			2,854			4,501
Deferred income tax expense	—			—			—			1,388
Changes in operating assets and liabilities:
Accounts receivable	(7,283		)	(30,540		)	(4,232		)	(14,174		)
Prepaid expenses and other	176			(1,400		)	37			2
Accounts payable	(2,327		)	1,751			373			(478		)
Accrued liabilities	(767		)	(3,811		)	5,192			6,621
Net cash provided by operating activities	22,430			150,811			154,117			70,006

Cash flows from investing activities:
Capital expenditures	(34,553		)	(123,767		)	(121,087		)	(248,463		)
Acquisition of Water Assets	—			—			—			(131,528		)
Acquisition of Vantage Midstream Assets	—			—			(600,000		)	—
Other acquisitions	—			(7,654		)	—			—
Net cash used in investing activities	(34,553		)	(131,421		)	(721,087		)	(379,991		)

Cash flows from financing activities:
Purchase price in excess of related party net assets	—			—			—			(68,470		)
Proceeds from borrowings	20,000			76,000			233,000			313,000
Repayments of borrowings	—			—			(186,000		)	(170,000		)
Costs related to initial public offering	—			—			—			(129		)
Common units issuance, net of offering costs	—			—			620,330			171,902
Additions to deferred financing costs	—			(81		)	(11,801		)	3
Contributions from parent, net	—			—			39			78,480
Distributions paid to GP Holdings	(10,041		)	(26,218		)	(25,473		)	(17,021		)
Distributions paid to common unitholders	—			(78,223		)	(46,239		)	(17,017		)
Employee tax withholding for settlement of phantom unit award vestings	—			—			(2,649		)	—
Net cash provided by (used in) financing activities	9,959			(28,522		)	581,207			290,748

Net (decrease) increase in cash	(2,164		)	(9,132		)	14,237			(19,237		)
Cash at the beginning of the period	12,702			21,834			7,597			26,834
Cash at the end of the period	$	10,538		$	12,702		$	21,834		$	7,597

Rice Midstream Partners LP

Consolidated Statements of Cash Flows - (Continued)



	Successor		Predecessor
	Period from November 13, 2017 to December 31, 2017		Period from January 1, 2017 to November 12, 2017		Years Ended December 31,
(in thousands)	Period from November 13, 2017 to December 31, 2017		Period from January 1, 2017 to November 12, 2017		2016		2015
Supplemental disclosure of cash flow information:
Cash paid for interest	$	1,836	$	7,331	$	2,652	$	3,146
Capital expenditures financed by accounts payable	4		15,197		2,239		—
Noncash elimination of deferred tax liabilities for the Water Assets	—		—		—		7,715

The accompanying notes are an integral part of these Consolidated Financial Statements.

Rice Midstream Partners LP

Consolidated Statements of Partner s ’ Capital



Predecessor				Limited Partners
(in thousands)	Parent Net Equity			Common			Subordinated			General Partner			Total
Balance at January 1, 2015	$	36,594		$	442,451		$	(49,101	)	$	—		$	429,944
Contribution from parent, net	78,480			—			—			—			78,480
Incentive compensation expense	1,044			—			—			—			1,044
Equity compensation expense	399			4,020			—			—			4,419
Offering costs related to the initial public offering	—			(129		)	—			—			(129		)
Distributions to unitholders	—			(17,019		)	(17,019		)	—			(34,038		)
Issuance of common units, net of offering costs	—			171,902			—			—			171,902
Elimination of current and deferred tax liabilities	7,715			—			—			—			7,715
Pre-acquisition net income allocated to general partner	7,296			—			—			—			7,296
Water Assets from Rice Energy	(131,528		)	—			—			—			(131,528		)
Purchase price in excess of net assets from Rice Energy	—			(8		)	(68,462		)	—			(68,470		)
Net income	—			23,340			21,859			—			45,199
Balance at December 31 2015	$	—		$	624,557		$	(112,723	)	$	—		$	511,834
Contributions from parent, net	—			—			39			—			39
Equity compensation expense	—			306			—			—			306
Distributions to unitholders	—			(46,243		)	(24,930		)	(540		)	(71,713		)
Issuance of common units to public, net of offering costs	—			620,330			—			—			620,330
Net income	—			76,985			43,197			1,428			121,610
Balance at December 31, 2016	$	—		$	1,275,935		$	(94,417	)	$	888		$	1,182,406
Equity compensation expense	—			497			—			—			497
Distributions to unitholders	—			(78,227		)	(30,588		)	(5,667		)	(114,482		)
Net income	—			105,432			41,225			6,182			152,839
Balance at November 12, 2017	$	—		$	1,303,637		$	(83,780	)	$	1,403		$	1,221,260


Successor
Balance at November 13, 2017	—			1,549,688			605,839			344,141			2,499,668
Equity compensation expense	—			17			—			—			17
Net income	—			16,920			6,615			1,599			25,134
Balance, December 31, 2017	$	—		$	1,566,625		$	612,454		$	345,740		$	2,524,819

The accompanying notes are an integral part of these Consolidated Financial Statements.

Rice Midstream Partners LP

Notes to Consolidated Financial Statements


1.	Summary of Significant Accounting Policies and Related Matters

Organization and Basis of Presentation

Rice Midstream Partners LP (Rice Midstream Partners or the Partnership) is a growth-oriented Delaware limited partnership formed by Rice Energy Inc. (Rice Energy) in August 2014. On November 13, 2017 (the Merger Date), EQT Corporation (EQT) acquired Rice Energy pursuant to the Agreement and Plan of Merger, dated as of June 19, 2017 (as amended, the Merger Agreement), by and among EQT, Rice Energy and an indirect, wholly-owned subsidiary of EQT. Pursuant to the Merger Agreement, Rice Energy ultimately, through a series of mergers (the Mergers), merged with and into an indirect, wholly-owned subsidiary of EQT that continued as the surviving entity.

The Mergers resulted in EQT gaining control of Rice Midstream Management LLC (Midstream Management), the general partner of the Partnership. As a result of this change in control, the Partnership became a consolidated subsidiary of EQT. EQT’s acquisition of Midstream Management was accounted for using the acquisition method, which required the assets and liabilities acquired to be recorded at fair value with any excess purchase price recognized as goodwill. The Partnership elected to apply pushdown accounting and thus has reflected its assets and liabilities, including goodwill, at the fair values estimated by EQT on the Merger Date with the related adjustment to the Partnership’s net assets recorded in equity. As a result, the Partnership’s consolidated financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented. The periods prior to the Mergers are identified as Predecessor and the period after the Mergers is identified as Successor.

As a result of the Mergers, EQT became the indirect parent of Midstream Management and acquired beneficial ownership of 3,623 common units representing limited partner interests, 28,753,623 subordinated units representing limited partner interests and all incentive distribution rights of the Partnership, all of which are held by Rice Midstream GP Holdings LP (GP Holdings), an indirect, wholly-owned subsidiary of EQT. Please see Note 2 for further information regarding the Mergers.

On September 26, 2016, the Partnership entered into a Purchase and Sale Agreement (as amended, the Midstream Purchase Agreement), by and between the Partnership and Rice Energy relating to its acquisition from Rice Energy of the entities owning the midstream assets (the Vantage Midstream Asset Acquisition) associated with Rice Energy’s acquisition of Vantage Energy, LLC and Vantage Energy II, LLC (collectively, Vantage) and their subsidiaries (the Vantage Acquisition). Pursuant to the terms of the Midstream Purchase Agreement, and following the closing of the Vantage Acquisition, on October 19, 2016, the Partnership acquired from Rice Energy all of the outstanding membership interests of Vantage Energy II Access, LLC and Vista Gathering, LLC (collectively, the Vantage Midstream Entities). The Partnership’s acquisition of the Vantage Midstream Entities from Rice Energy is accounted for as a combination of entities under common control at historical cost. As the Vantage Midstream Asset Acquisition occurred concurrently with the Vantage Acquisition, no predecessor period existed which would warrant retrospective recast of our financial statements. See Note 2 for further detail regarding the Vantage Midstream Asset Acquisition.

On November 4, 2015, the Partnership entered into a Purchase and Sale Agreement (the Purchase Agreement), by and between the Partnership and Rice Energy. Pursuant to the terms of the Purchase Agreement, the Partnership acquired all of the outstanding limited liability company interests of Rice Water Services (PA) LLC and Rice Water Services (OH) LLC, two wholly-owned indirect subsidiaries of EQT (following EQT’s acquisition of Rice Energy) that own and operate a portion of EQT’s water services business. The acquired business includes Pennsylvania and Ohio fresh water distribution systems and related facilities that provide access to fresh water from the Monongahela River, the Ohio River and other regional water sources in Pennsylvania and Ohio (the Water Assets). Certain subsidiaries of EQT have also granted the Partnership, until December 31, 2025, (i) the exclusive right to develop water treatment facilities in the areas of dedication defined in the amended and restated water services agreements (the Water Services Agreement) and (ii) an option to purchase any water treatment facilities acquired by such subsidiaries in those areas at the applicable acquisition cost (collectively, the Option). The acquisition was accounted for as a combination of entities under common control, and as such, the Partnership’s consolidated financial statements have been retrospectively recast for all periods prior to November 1, 2015, the effective date of acquisition of the Water Assets, to include the historical results of the Water Assets.

The Partnership does not have any employees. Prior to the completion of the Mergers, operational support for the Partnership was provided by Rice Energy, and employees of Rice Energy managed and conducted the Partnership’s daily business operations. Following the Mergers, operational support for the Partnership is provided by EQT and certain of its subsidiaries, whose employees manage and conduct the Partnership’s daily business operations.

The Partnership’s cost of doing business incurred by Rice Energy and EQT in the Predecessor and Successor periods, respectively, on behalf of the Partnership have been reflected in the accompanying consolidated financial statements. These costs include general and administrative expenses allocated by Rice Energy and EQT to the Partnership in exchange for:


•	business services, such as payroll, accounts payable and facilities management;


•	corporate services, such as finance and accounting, legal, human resources and public and regulatory policy; and


•	employee compensation.

Nature of Business

The Partnership is a fee-based, growth-oriented limited partnership formed by Rice Energy to own, operate, develop and acquire midstream assets in the Appalachian Basin. As of December 31, 2017, the Partnership provides midstream services to EQT and third parties within three counties in the Appalachian Basin through two primary segments: the gathering and compression segment and the water services segment.

Gathering and compression segment. The Partnership’s gathering assets consist of a high-pressure dry gas gathering system and associated compression in Washington and Greene Counties, Pennsylvania. The Partnership provides gathering and compression services under long-term, fixed price per unit contracts to EQT and third parties.

Water services segment. The Partnership’s water services assets consist of water pipelines, impoundment facilities, pumping stations, take point facilities and measurement facilities which are used to support well completion activities and to collect and recycle or dispose of flowback and produced water for EQT and third parties in Washington and Greene Counties, Pennsylvania and Belmont County, Ohio. The Partnership provides water services under long-term, fee-based contracts to EQT and third parties.

Principles of Consolidation

The consolidated financial statements of the Partnership have been prepared in accordance with accounting principles generally accepted in the United States (GAAP). The consolidated financial statements include the accounts of the Partnership and its subsidiaries. All intercompany transactions have been eliminated in consolidation. Transactions between the Partnership and Rice Energy in the Predecessor period and between the Partnership and EQT in the Successor period have been identified in the consolidated financial statements as transactions between affiliates and are discussed in further detail in Note 9.

Use of Estimates

The Partnership prepares its consolidated financial statements in conformity with GAAP, which require management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Risks and Uncertainties

The Partnership relies on revenues generated from its gathering and water services assets, all of which are located in three counties within the Appalachian Basin. As a result of this concentration, the Partnership may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area. Additionally, following the consummation of the Mergers, the Partnership is substantially dependent on EQT as its most significant customer, as EQT combined with Rice Energy for the period prior to the Mergers, represented substantially all of the Partnership’s gathering and compression revenues and 96% of the Partnership’s water revenues for the year ended December 31, 2017 . The Partnership expects to derive a substantial majority of its revenues from EQT for the foreseeable future. As a result, any event, whether in the Partnership’s dedicated areas or otherwise, that adversely affects EQT’s production, drilling and completion schedule, financial condition, leverage, market reputation, liquidity, results of operations or cash flows may adversely affect its revenues and cash available for distribution.

The Partnership manages the credit risk of sales to third parties by limiting dealings to those third parties meeting specified criteria for credit and liquidity strength and by actively monitoring these accounts. The Partnership may request a letter of credit, guarantee, performance bond or other credit enhancement from a third party in order for that third party to meet the Partnership’s credit criteria. The Partnership did not experience any significant defaults on accounts receivable for the years ended December 31, 2017 , 2016 and 2015 .

Revenue Recognition

Gathering, compression and water service revenues are recognized in the period service is provided. The revenue the Partnership recognizes from gathering and compression services is generally directly related to the volume of natural gas that flows through its systems and revenue the Partnership recognizes from water services is generally directly related to the volume of water that is delivered, recycled or disposed.

Cash

The Partnership maintains cash at financial institutions which may at times exceed federally insured amounts and which may at times exceed consolidated balance sheet amounts due to outstanding checks. The Partnership has no accounts that are considered cash equivalents.

Accounts Receivable

Accounts receivable are stated at their historical carrying amount. The Partnership extends credit to parties in the normal course of business based upon management’s assessment of their creditworthiness. An allowance is provided for those accounts for which collection is estimated as doubtful; uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the party. There was no allowance recorded for any of the years presented in the consolidated financial statements.

Asset Retirement Obligations

The Partnership is under no legal or contractual obligation to restore or dismantle its gathering pipelines or compression facilities upon abandonment. Additionally, the Partnership operates and maintains its gathering systems and it intends to do so as long as supply and demand for natural gas exists, which the Partnership expects for the foreseeable future. Therefore, asset retirement obligations are generally not required for gathering systems as the Partnership believes that these assets have indeterminate useful lives, if properly maintained. Absent the lack of legal or contractual obligations, the Partnership is not able to make a reasonable estimate of when future dismantlement and removal dates of gathering systems may occur. The asset retirement obligations recorded in the consolidated balance sheets primarily relate to its water services assets. The Partnership records a liability for such asset retirement obligations and capitalizes a corresponding amount for asset retirement costs. The liability is estimated using the present value of expected future cash flows, adjusted for inflation and discounted at the Partnership’s credit adjusted risk-free rate. The current portion of asset retirement obligations is recorded in other accrued liabilities on the consolidated balance sheets.

A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations for the years ended December 31, 2017 and 2016 is as follows:



Predecessor
(in thousands)
Balance at December 31, 2015	$	3,048
Liabilities incurred	46
Liabilities assumed in Vantage Midstream Asset Acquisition	2,452
Liabilities settled	(46		)
Accretion expense	290
Balance at December 31, 2016	$	5,790
Liabilities incurred	384
Liabilities settled	(88		)
Accretion expense	393
Revisions in estimated liabilities	351
Balance at November 12, 2017	$	6,830


Successor
Revisions in estimated liabilities ⁽¹⁾	2,489
Balance at November 13, 2017	9,319
Liabilities settled	(20		)
Accretion expense	22
Balance at December 31, 2017	$	9,321


(1)	Revisions in estimated liabilities reflect changes in assumptions associated with retirement costs and/or the estimated timing of settling retirement obligations. These revisions were recorded as an opening balance sheet adjustment at the Merger Date.

Interest

The Partnership capitalizes interest on expenditures for significant capital projects while activities are in progress to bring the assets to their intended use. Upon completion of construction of the asset, the associated capitalized interest costs are included within the Partnership’s asset base and depreciated accordingly. The following table summarizes the components of the Partnership’s interest incurred for the respective periods.



	Successor		Predecessor
	Period from November 13, 2017 to December 31, 2017		Period from January 1, 2017 to November 12, 2017		Years Ended December 31,
(in thousands)	Period from November 13, 2017 to December 31, 2017		Period from January 1, 2017 to November 12, 2017		2016		2015
Interest incurred:
Interest expensed	$	826	$	7,053	$	3,931	$	3,164
Interest capitalized	605		594		175		222
Total incurred	$	1,431	$	7,647	$	4,106	$	3,386

Property and Equipment

In the Predecessor period, property and equipment was recorded at cost and was being depreciated over the estimated useful life of assets on a straight-line basis. Gathering pipelines and compressor stations were depreciated over a useful life of 60 years. Water pipelines, pumping stations and impoundment facilities were depreciated over a useful life of 10 to 15 years. In the Successor period, property and equipment is recorded at cost and is being depreciated using composite rates on a straight-line basis over the estimated useful lives of the assets. The overall rate of depreciation for the Successor period ended December 31, 2017 was approximately 3.7% . Effective as of the Merger Date, the Partnership estimates gathering pipelines to have useful lives ranging from 20 years to 65 years, compression equipment to have useful lives ranging from 20 years to 50 years and water equipment to have useful lives ranging from 10 to 15 years. As circumstances warrant, depreciation rates are reviewed to determine if any changes in the underlying assumptions are necessary.

The following table provides detail of property and equipment presented in the consolidated balance sheets at December 31, 2017 and 2016 .



(in thousands)	As of December 31, 2017			As of December 31, 2016
(in thousands)	As of December 31, 2017			As of December 31, 2016
Natural gas gathering assets	$	1,138,581		$	675,830
Natural gas gathering assets in progress	101,154			3,780
Accumulated depreciation	(4,020		)	(21,615		)
Natural gas gathering assets, net	1,235,715			657,995
Water service assets	176,209			165,482
Water service assets in progress	17,616			4,060
Accumulated depreciation	(3,363		)	(24,981		)
Water service assets, net	190,462			144,561
Other property and equipment, net	5,625			2,471
Property and equipment, net	$	1,431,802		$	805,027

Whenever events or changes in circumstances indicate that the carrying amount of long-lived assets may not be recoverable, the Partnership reviews its 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, the Partnership estimates an impairment loss equal to the difference between the carrying value and fair value of the assets.

Goodwill

Goodwill is the total consideration of an acquisition less the fair value of the identifiable net assets of the acquired business, including identifiable intangible assets. The Partnership evaluates goodwill for impairment at least annually during the fourth quarter, or whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. A reporting unit is an operating segment or a component of an operating segment for which discrete financial information is available and reviewed by management on a regular basis. The Partnership identifies its operations within two reporting units: (i) PA Gathering, and (ii) Water Services (which had not been ascribed goodwill). During the first quarter of 2017, the Partnership adopted Accounting Standards Update (ASU) 2017-04, “Intangibles — Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” This ASU eliminates Step 2 from the goodwill impairment test which previously required measurement of any goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Under ASU 2017-04, the Partnership compares the fair value of its reporting units with its carrying value amount and recognizes an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value, without exceeding the total amount of goodwill allocated to that reporting unit.

The Partnership may first consider qualitative factors to assess whether there are indicators that it is more likely than not that the fair value of a reporting unit may not exceed its carrying amount. To the extent that such indicators exist, the Partnership would complete a quantitative goodwill impairment test. The Partnership may also perform a quantitative goodwill impairment test at its discretion without performing the qualitative assessment. If the carrying value of the goodwill of a reporting unit exceeds its fair value, the difference is recognized as an impairment charge.

The Partnership’s fourth quarter 2017 annual test, which was performed in the Predecessor period, included the assessment of factors to determine whether it was more likely than not that the fair value of each reporting unit was less than its carrying value. Due to the reduction in its unit price following the announcement of the Mergers, the Partnership concluded that it would bypass a qualitative assessment and proceed directly to a quantitative impairment assessment for purposes of its annual test. The Partnership used a combination of the income approach and market approach to estimate the fair value of the reporting unit. For purposes of the income approach, the Partnership employed the discounted cash flow method, which used significant inputs not observable on the public market (Level 3), to determine fair value on the present value of estimated future cash flows, discounted at a risk-adjusted rate. The income approach included the Partnership’s estimates and assumptions related to future throughput volumes, operating revenues, operating costs, capital spending and changes in working capital. In addition, the Partnership employed the guideline public company method and the market capitalization method within the market approach to determine the fair value of the reporting units. The guideline public company method considers market multiples derived from market prices of publicly traded stocks of companies engaged in similar lines of business as the Partnership’s reporting units. The market capitalization method uses the Partnership’s stock price to derive fair value. From a market capitalization standpoint,

the Partnership utilized a 30-day volume weighted average price look-back as of its annual assessment date. Estimating the fair value of the reporting units requires considerable judgment and determining fair value is sensitive to changes in assumptions impacting management’s estimates of the future financial results of the reporting units. Although the Partnership believes the estimates and assumptions used in estimating the fair value of its reporting units are reasonable and appropriate, different assumptions and estimates could materially impact the calculated fair value of the reporting units. Additionally, actual future results could differ from its current estimates and assumptions. As a result of the Partnership’s annual impairment test, it determined that the fair value of the reporting units exceeded its carrying value under each approach, both individually and on a weighted basis.

The Partnership completed an assessment of qualitative factors in the Successor period to determine whether it was more likely than not that the fair value of each reporting unit was less than its carrying value. The qualitative assessment encompassed a review of events and circumstances specific to the reporting unit with goodwill, as well as circumstances specific to the entity as a whole. Some of the factors considered in the Partnership’s qualitative assessment included macroeconomic conditions, industry and market conditions, cost factors affecting the business and performance of the Partnership’s unit price. In considering the totality of the qualitative factors assessed, based on the weight of evidence, circumstances did not exist that would indicate it was more likely than not that goodwill was impaired in the Successor period.

Changes in the value of goodwill during the years ended December 31, 2017 and 2016 , all of which resides within the Partnership’s gathering and compression segment, are detailed below.



Predecessor
(in thousands)	Goodwill
Balance, December 31, 2015	$	39,142
Additions	455,438
Balance, December 31, 2016	$	494,580
Additions	—
Balance, November 12, 2017	$	494,580


Successor
Additional goodwill related to pushdown accounting, net of previously recognized ⁽¹⁾	852,338
Balance, December 31, 2017	$	1,346,918


(1)	The Partnership has recorded goodwill as the excess of the estimated enterprise value over the sum of the fair value amounts allocated to the Partnership’s assets and liabilities. Goodwill was allocated to the value attributed to additional growth opportunities, synergies and operating leverage within the Partnership’s gathering and compression segment. See Note 2 for further information.

Intangible Assets

In the Predecessor period, the Partnership’s intangible assets were primarily comprised of customer contracts with EQT that were acquired as part of an April 2014 acquisition of certain gas gathering assets in Washington and Greene Counties, Pennsylvania. These intangible assets were valued based upon the estimated fair value of the assets at the acquisition date. The customer contracts were assigned a useful life of 30 years and amortized on a straight-line basis. At the Merger Date, the intangible assets that were related to customer contracts with EQT were eliminated through the application of pushdown accounting.

Segment Reporting

Business segments are components of the Partnership for which separate financial information is produced internally and are subject to evaluation by the Partnership’s chief operating decision maker in deciding how to allocate resources. The Partnership reports its operations in two segments: (i) gathering and compression and (ii) water services, which reflect its lines of business. Business segments are evaluated for their contribution to the Partnership’s consolidated results based on operating income. All of the Partnership’s operating revenues, income from operations and assets are located in the United States. See Note 10 for additional information regarding segment reporting.

Net Income per Limited Partner Unit

The Partnership’s net income is allocated to the limited partners, including subordinated unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to the incentive distribution rights held by GP Holdings. Basic and diluted net income per limited partner unit is calculated by dividing limited partners’ interest in net income,

less general partner incentive distributions and pre-acquisition net income attributable to the general partner, by the weighted average number of outstanding limited partner units during the period.

We compute earnings per unit using the two-class method for master limited partnerships. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the Partnership’s partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.

We calculate net income available to limited partners based on the distributions pertaining to the current period’s net income. The allocation of undistributed earnings, or net income in excess of distributions, to the incentive distribution rights is limited to cash available for distribution for the period. The Partnership’s net income allocable to the limited partners is allocated between common and subordinated unitholders by applying the provisions of the Partnership’s partnership agreement under the two-class method that govern actual cash distributions as if all earnings for the period had been distributed. Any common units issued during the period are included on a weighted-average basis for the days in which they were outstanding. Net income attributable to the Water Assets for the periods prior to their acquisition was not allocated to the limited partners for purposes of calculating net income per limited partner unit as these results are not attributable to limited partners of the Partnership.

Diluted net income per limited partner unit reflects the potential dilution that could occur if securities or agreements to issue common units, such as awards under the Rice Midstream Partners LP 2014 Long Term Incentive Plan (the LTIP), were exercised, settled or converted into common units. When it is determined that potential common units should be included in diluted net income per limited partner unit calculation, the impact is reflected by applying the treasury stock method.

Recently Issued Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, “Revenue from Contracts with Customers.” The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers - Deferral of the Effective Date” which approved a one year deferral of ASU 2014-09 to annual reporting periods beginning after December 15, 2017. During the third quarter of 2017, the Partnership substantially completed its detailed review of the impact of the standard on each of its contracts. The Partnership adopted the ASUs using the modified retrospective method of adoption on January 1, 2018 and did not record an adjustment to equity. The Partnership does not expect the standard to have a significant impact on net income in 2018. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers including disaggregation of revenue and remaining performance obligations. The Partnership implemented processes and controls to ensure new contracts are reviewed for the appropriate accounting treatment and to generate the disclosures required under the new standard in the first quarter of 2018.

In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842)” which requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The new guidance is effective for annual and interim reporting periods beginning after December 15, 2018. The Partnership continues to evaluate its agreements to assess the impact of the new guidance on its financial statements.

In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting.” ASU 2016-09 affects entities that issue share-based payment awards to their employees. ASU 2016-09 is designed to simplify several aspects of accounting for share-based payment award transactions, including: (i) income tax consequences, (ii) classification of awards as either equity or liabilities, (iii) classification on the statement of cash flows and (iv) forfeiture rate calculations. The Partnership adopted ASU 2016-09 on January 1, 2017 and determined that the standard did not have a material impact on the consolidated financial statements.

In January 2017, the FASB issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. This standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. The Partnership adopted this ASU on January 1, 2017, and has determined that the new ASU could potentially have a material impact on future consolidated financial statements for acquisitions that are not considered to be businesses.

In January 2017, the FASB issued ASU 2017-04, “Simplifying the Test of Goodwill Impairment.” ASU 2017-04 simplifies the quantitative goodwill impairment test requirements by eliminating the requirement to calculate the implied fair value of goodwill (Step 2 of the current goodwill impairment test). Instead, a partnership would record an impairment charge based on the excess of a reporting unit’s carrying value over its fair value (measured in Step 1 of the current goodwill impairment test). This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and early adoption is permitted. Entities will apply the standard’s provisions prospectively. The Partnership adopted ASU 2017-04 on January 1, 2017 and determined that this standard will not have a material quantitative effect on the financial statements in the future, unless an impairment charge is necessary.

In May 2017, the FASB issued ASU 2017-09, “Stock Compensation (Topic 718): Scope of Modification Accounting”. ASU 2017-09 clarifies when changes to the terms or conditions of a share-based payment award must be accounted for as modifications. The guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017, with early adoption permitted. The Partnership is currently evaluating the impact that this guidance will have on its consolidated financial statements.

Subsequent Events

The Partnership has evaluated subsequent events through the date of the financial statement issuance.


2.	Mergers and Acquisitions

Rice Energy’s Merger with EQT

EQT performed a preliminary valuation of the fair value of the Partnership’s assets and liabilities as of the Merger Date. The fair value of the Partnership’s current assets and current liabilities were assumed to approximate their carrying values. The estimated fair value of the Partnership’s long-lived tangible assets was determined utilizing observable market inputs where available or estimated replacement cost adjusted for a usage or obsolescence factor. The estimated fair value of the Partnership’s long-term liabilities was determined utilizing observable market inputs where available or estimated based on their current carrying values. The Partnership has recorded goodwill as the excess of the estimated enterprise value over the sum of the fair value amounts allocated to the Partnership’s assets and liabilities. Goodwill was allocated to the value attributed to additional growth opportunities, synergies and operating leverage within the Partnership’s gathering and compression segment.

The following table summarizes the preliminary allocation of the fair value of the assets and liabilities of the Partnership as of the Merger Date through pushdown accounting from EQT. The preliminary allocation to certain assets and/or liabilities may be adjusted by material amounts as EQT continues to finalize the fair value estimates. Certain data necessary to complete the purchase price allocation is not yet available, including, but is not limited to, final appraisals of assets acquired and liabilities assumed. EQT expects to complete the purchase price allocation once it has received all of the necessary information, at which time the value of the assets and liabilities will be revised as appropriate.



(in thousands)	At November 13, 2017
Estimated Value of RMP	$	2,499,668

Estimated Fair Value of Assets Acquired and Liabilities Assumed:
Current assets	$	65,300
Property and equipment, net	1,419,077
Other non-current assets	47
Current liabilities	(56,351		)
Revolving credit facility	(266,000		)
Other non-current liabilities	(9,323		)
Total estimated fair value of assets acquired and liabilities assumed	$	1,152,750
Goodwill	$	1,346,918

Vantage Acquisition

On September 26, 2016, the Partnership entered into the Midstream Purchase Agreement. Pursuant to the terms of the Midstream Purchase Agreement, and following the closing of the Vantage Acquisition, on October 19, 2016, the Partnership acquired from Rice Energy all of the outstanding membership interests of the Vantage Midstream Entities. The Vantage

Midstream Entities own midstream assets, including approximately 30 miles of dry gas gathering and compression assets and water assets. In consideration for the acquisition of the Vantage Midstream Asset Acquisition, the Partnership paid Rice Energy $600 million in aggregate consideration, which the Partnership paid in cash with the net proceeds of its private placement of common units (the 2016 Private Placement) of $441 million and borrowings under its revolving credit facility (defined in Note 3) of $159 million . The purchase price allocation ascribed approximately $144.6 million to property and equipment, $ 0.4 million in net working capital, and $455 million to goodwill.

The Partnership’s acquisition of the Vantage Midstream Entities from Rice Energy was accounted for as a combination of entities under common control at historical cost. As the Vantage Midstream Asset Acquisition occurred concurrently with the Vantage Acquisition, no predecessor period existed which would warrant retrospective recast of the Partnership’s financial statements.

The purchase price allocation was performed by Rice Energy. The fair values of the assets acquired were determined using various valuation techniques, including the cost approach. The assumed purchase price and fair values were prepared with the assistance of external specialists, and represented Rice Energy’s best estimate of the fair values of the assets acquired. Goodwill was allocated to the value attributed to additional growth opportunities, synergies and operating leverage within the Partnership’s gathering and compression segment as of December 31, 2016.

Post-Acquisition Operating Results

The Vantage Midstream Entities contributed the following to the Partnership’s consolidated operating results for the period from November 13, 2017 to December 31, 2017 , for the period from January 1, 2017 to November 12, 2017 and for the period from October 19, 2016 to December 31, 2016.



	Successor		Predecessor
	Period from November 13, 2017 to December 31, 2017		Period from January 1, 2017 to November 12, 2017		Period from October 19. 2016 to December 31, 2016
(in thousands)	Period from November 13, 2017 to December 31, 2017		Period from January 1, 2017 to November 12, 2017		Period from October 19. 2016 to December 31, 2016
Operating revenues	$	6,529	$	51,190	$	8,571
Net income	$	5,412	$	38,200	$	4,303

Pro Forma Information

The following unaudited pro forma combined financial information presents the Partnership’s results as though the acquisition of the Vantage Midstream Entities and the 2016 Private Placement had been completed at January 1, 2015.



	Predecessor
	Year Ended December 31,
(in thousands, except per unit data)	2016		2015
Operating revenues	$	253,817	$	156,944
Limited partner net income	$	150,846	$	67,199
Earnings per common unit (basic)	$	1.54	$	0.84
Earnings per common unit (diluted)	$	1.54	$	0.83
Earnings per subordinated units	$	1.55	$	0.84


3.	Revolving Credit Facility

On December 22, 2014 , Rice Midstream OpCo LLC, the Partnership’s wholly-owned subsidiary (Rice Midstream OpCo), e ntered into a revolving credit agreement (as amended, the Revolving Credit Facility) with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders.

As of December 31, 2017 , the Revolving Credit Facility provided for lender commitments of $850 million , with an additional $200 million of commitments available under an accordion feature, subject to lender approval. As of December 31, 2017, Rice Midstream OpCo had $286 million of borrowings and $1 million of letters of credit outstanding under this facility, resulting in availability of $563 million . The average daily outstanding balance of the credit facility was approximately $216 million and interest was incurred on the facility at a weighted average annual interest rate of 3.1% during 2017 . The Revolving Credit Facility is available to fund working capital requirements and capital expenditures, to purchase assets, to pay distributions, to repurchase units and for general partnership purposes. The Revolving Credit Facility matures on December 22, 2019 .

Principal amounts borrowed are payable on the maturity date, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for Eurodollar loans. Rice Midstream OpCo may elect to borrow in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR Rate plus an applicable margin ranging from 200 to 300 basis points, depending on the leverage ratio in effect from time to time, and base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 100 to 200 basis points, depending on the leverage ratio in effect from time to time. The carrying amount of the Revolving Credit Facility is comprised of borrowings for which interest accrues under a fluctuating interest rate structure. Accordingly, the carrying value approximates fair value as of December 31, 2017 and represents a Level 2 measurement. Rice Midstream OpCo also pays a commitment fee based on the undrawn commitment amount ranging from 37.5 to 50 basis points.

The Revolving Credit Facility is secured by mortgages and other security interests on substantially all of its properties and is guaranteed by the Partnership and its restricted subsidiaries. The Revolving Credit Facility limits the Partnership’s ability to, among other things, incur or guarantee additional debt; redeem or repurchase units or make distributions under certain circumstances; 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.

The Revolving Credit Facility also requires the Partnership to maintain the following financial ratios:


•	an interest coverage ratio, which is the ratio of the Partnership’s consolidated EBITDA (as defined within the Revolving Credit Facility) to its consolidated current interest expense of at least 2.50 to 1.0 at the end of each fiscal quarter;


•	a consolidated total leverage ratio, which is the ratio of consolidated debt to consolidated EBITDA, of not more than 4.75 to 1.0, and after electing to issue senior unsecured notes, a consolidated total leverage ratio of not more than 5.25 to 1.0, and, in each case, with certain increases in the permitted total leverage ratio following the completion of a material acquisition; and


•	if the Partnership elects to issue senior unsecured notes, a consolidated senior secured leverage ratio, which is the ratio of consolidated senior secured debt to consolidated EBITDA, of not more than 3.50 to 1.0.

The Partnership was in compliance with such covenants and ratios as of December 31, 2017 .


4.	Commitments and Contingencies

Litigation

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

The Partnership is 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. The Partnership has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory requirements. The estimated costs associated with identified situations that require remedial action are accrued. 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 its business, financial condition, results of operations, liquidity or ability to make distributions.

Lease Obligations

The Partnership has lease obligations for compression equipment under existing contracts with third parties. Rent expense included in operation and maintenance expense for the periods from November 13, 2017 to December 31, 2017 and from January 1, 2017 to November 12, 2017, and the years ended December 31, 2016 and 2015 was $0.3 million , $1.2 million , $1.6 million and

$1.7 million , respectively. Future payments for this equipment as of December 31, 2017 totaled $3.6 million (2018: $1.2 million ; 2019: $1.2 million ; 2020: $0.6 million ; 2021: $0.3 million ; and 2022: $0.3 million ).


5.	Partners’ Capital

The following table presents the Partnership’s common and subordinated units issued from January 1, 2016 through December 31, 2017 :



	Limited Partners			GP Holdings
	Common	Subordinated	Total	Ownership %
Balance, January 1, 2016	42,163,749	28,753,623	70,917,372	41	%
Equity offering in June 2016	9,200,000	—	9,200,000
Equity offering in October 2016	20,930,233	—	20,930,233
Common units issued under at the market program ⁽¹⁾	944,700	—	944,700
Vested phantom units, net	280,451	—	280,451
Balance, December 31, 2016	73,519,133	28,753,623	102,272,756	28	%
Vested phantom units, net ⁽²⁾	30,352	—	30,352	—	%
Balance, December 31, 2017	73,549,485	28,753,623	102,303,108	28	%

(1)

In May 2016, the Partnership entered into an equity distribution agreement that established an at the market common unit offering program, pursuant to which a group of managers, acting as sales agents, may sell RMP common units having an aggregate offering price of up to $ 100 million (the ATM Program). The Partnership has used the net proceeds from the sale of common units pursuant to the ATM Program for general partnership purposes, including repayment of debt, acquisitions and capital expenditures.


(2)	All 2017 phantom unit vestings occurred prior to the Merger Date.

As of December 31, 2017 , GP Holdings owned an approximate 28% limited partner interest in the Partnership consisting of 3,623 common units and 28,753,623 subordinated units, as well as all of the incentive distribution rights in the Partnership. See Note 7 for information regarding the Partnership’s subordination period.


6.	Phantom Unit Awards

The Partnership’s general partner has granted phantom unit awards under the LTIP to certain non-employee directors of the Partnership that provide services to the Partnership under an omnibus agreement with EQT. Pursuant to the LTIP, the maximum aggregate number of common units that may be issued pursuant to any and all awards under the LTIP shall not exceed 5,000,000 common units, subject to adjustment due to recapitalization or reorganization, or related to forfeitures or the expiration of awards, as provided under the LTIP.

The equity-based awards are valued at the date of issuance and the related compensation cost is recognized into earnings on a straight-line basis over the vesting period. The equity-based awards will cliff vest at the end of the requisite service period of approximately one year. The Partnership recorded $0.5 million , $2.8 million and $4.1 million of equity compensation cost related to these awards for the period from January 1, 2017 to November 12, 2017 and the years ended December 31, 2016 and 2015 , respectively, in general and administrative expenses on the consolidated statements of operations. At December 31, 2017 , total unrecognized compensation cost expected to be recognized over the remaining vesting periods was $0.2 million for these awards.

The following table summarizes the activity for the equity-based awards during the years ended December 31, 2017 and 2016 .



	Number of units		Weighted average grant date fair value
Total unvested, January 1, 2016	432,628		$	16.52
Granted	30,352		17.81
Vested	(399,158	)	16.52
Forfeited	(33,470	)	16.50
Total unvested - December 31, 2016	30,352		$	17.81
Granted ⁽¹⁾	20,688		24.41
Vested ⁽¹⁾	(30,352	)	17.81
Total unvested - December 31, 2017	20,688		$	24.41


(1)	All 2017 equity-based awards were granted or vested prior to the Merger Date.


7.	Net Income per Limited Partner Unit and Cash Distributions

Diluted net income per limited partner unit reflects the potential dilution that could occur if securities or agreements to issue common units, such as awards under the LTIP, were exercised, settled or converted into common units. When it is determined that potential common units should be included in diluted net income per limited partner unit calculation, the impact is reflected by applying the treasury stock method.

The following table presents the Partnership’s calculation of net income per limited partner unit for common and subordinated limited partner units.



	Successor		Predecessor
(in thousands, except per unit data)	Period from November 13, 2017 to December 31, 2017		Period from January 1, 2017 to November 12, 2017		Years Ended December 31,
(in thousands, except per unit data)	Period from November 13, 2017 to December 31, 2017		Period from January 1, 2017 to November 12, 2017		2016		2015
Net income	$	25,134	$	152,839	$	121,610	$	52,495
Less: Pre-acquisition net income allocated to general partner ⁽¹⁾	—		—		—		7,296
Less: General partner interest in net income attributable to incentive distribution rights	1,599		6,182		1,428		—
Limited partner net income	$	23,535	$	146,657	$	120,182	$	45,199

Net income allocable to common units	$	16,920	$	105,432	$	76,985	$	23,340
Net income allocable to subordinated units	6,615		41,225		43,197		21,859
Limited partner net income	$	23,535	$	146,657	$	120,182	$	45,199

Weighted-average limited partner units outstanding - basic:
Common units	73,549,485		73,535,414		52,822,030		30,700,864
Subordinated units	28,753,623		28,753,623		28,753,623		28,753,623
Total	102,303,108		102,289,037		81,575,653		59,454,487

Weighted-average limited partner units outstanding - diluted:
Common units ⁽²⁾	73,558,609		73,544,497		53,065,865		30,807,972
Subordinated units	28,753,623		28,753,623		28,753,623		28,753,623
Total	102,312,232		102,298,120		81,819,488		59,561,595

Net income per limited partner unit - basic:
Common units	$	0.23	$	1.43	$	1.46	$	0.76
Subordinated units ⁽³⁾	0.23		1.43		1.50		0.76
Total	$	0.23	$	1.43	$	1.47	$	0.76

Net income per limited partner unit - diluted:
Common units	$	0.23	$	1.43	$	1.45	$	0.76
Subordinated units ⁽³⁾	0.23		1.43		1.50		0.76
Total	$	0.23	$	1.43	$	1.47	$	0.76


(1)	Pre-acquisition net income allocated to the general partner relates to operations of the Water Assets for periods prior to their acquisition.


(2)	Diluted weighted-average limited partner common units includes the effect of 9,124 , 9,083 , 243,835 and 107,108 units for the period from November 13, 2017 to December 31, 2017 , the period from January 1, 2017 to November 12, 2017 and for the years ended December 31, 2016 and 2015 , respectively.

(3) Basic and diluted income per limited partner unit is presented as if all earnings for the period had been distributed. While it appears that more income is allocated to the subordinated unitholders than the common unitholders for the year ended December 31, 2016, the Partnership’s partnership agreement prevents the Partnership from making a distribution to the subordinated unitholders in excess of those to the common unitholders.

Subordinated Units

Following the consummation of the Mergers, EQT indirectly owned all of the Partnership’s subordinated units. The principal difference between the Partnership’s common units and subordinated units was that, under the partnership agreement, for any quarter during the subordination period, holders of the subordinated units were not entitled to receive any distribution from operating surplus until the common units had received the minimum quarterly distribution for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units did not accrue arrearages. As a result of the declaration of the Partnership’s fourth quarter 2017 cash distribution, which was paid on February 14, 2018, the subordination period with respect to the Partnership’s 28,753,623 subordinated units expired on February 15, 2018 and all of the outstanding Partnership subordinated units converted into Partnership common units on a one -for-one basis on that day.

Cash Distributions

Within 45 days after the end of each quarter, pursuant to the terms of its partnership agreement, the Partnership intends to distribute to the holders of common units on a quarterly basis all of its available cash to the extent it has sufficient cash after the establishment of cash reserves and the payment of its expenses, including payments to its general partner and affiliates. Following the consummation of the Mergers, all of the incentive distribution rights are held indirectly by EQT through GP Holdings. Incentive distribution rights represent the right to receive increasing percentages ( 15% , 25% and 50% ) of quarterly distributions from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved.

For any quarter in which the Partnership has distributed cash from operating surplus to the common unitholders in an amount equal to the minimum distribution, then the Partnership will distribute any additional available cash from operating surplus for that quarter among the unitholders and the incentive distribution rights holders in the following manner:



		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Per Unit	Unitholders	Incentive Distribution Rights Holders
Minimum Quarterly Distribution	$0.1875	100%	—%
First Target Distribution	above $0.1875 up to $0.2156	100%	—%
Second Target Distribution	above $0.2156 up to $0.2344	85%	15%
Third Target Distribution	above $0.2344 up to $0.2813	75%	25%
Thereafter	above $0.2813	50%	50%

In 2017 and 2016, cash distributions of $5.7 million and $0.5 million , respectively, were made to GP Holdings related to its incentive distribution rights in the Partnership based upon the level of distribution paid per common and subordinated unit.

The Board of Directors of the Partnership’s general partner declared the following cash distributions to the Partnership’s common and subordinated unitholders for the periods presented.



Quarters Ended	Total Quarterly Distribution per Unit		Date of Distribution
March 31, 2016	$	0.2100	May 12, 2016
June 30, 2016	$	0.2235	August 11, 2016
September 30, 2016	$	0.2370	November 10, 2016
December 31, 2016	$	0.2505	February 16, 2017
March 31, 2017	$	0.2608	May 18, 2017
June 30, 2017	$	0.2711	August 17, 2017
September 30, 2017	$	0.2814	November 16, 2017
December 31, 2017	$	0.2917	February 14, 2018


8.	Income Taxes

The Partnership is not subject to federal and state income taxes as a result of its limited partner structure. For federal and state income tax purposes, all income, expenses, gains, losses and tax credits generated by the Partnership flow through to the unitholders. As such, the Partnership does not record a provision for income taxes in the current period. Prior to the Partnership’s IPO, the Partnership’s income was included as part of Rice Energy’s consolidated federal tax return.

Prior to the acquisition of the Water Assets, the operations of the Water Assets were subject to income taxes and were included as part of Rice Energy’s consolidated federal tax return. Accordingly, the income tax effects associated with the operations of the Water Assets continued to be subject to income taxes until the Water Assets were acquired by the Partnership. Due to the Partnership’s status for U.S. federal and state income tax purposes, net current and deferred income tax liabilities of the Water Assets of $7.7 million eliminated through equity on the effective date of their acquisition by the Partnership. For the year ended December 31, 2015, the Partnership recorded income tax expense of approximately $5.8 million associated with the operations of the Water Assets prior to acquisition by the Partnership.

Pursuant to an agreement between the Partnership and the Internal Revenue Service (IRS) regarding the Partnership’s 2016 tax reporting, the Partnership had two short tax years for the calendar year 2016 as a result of a technical termination that occurred on February 22, 2016. This technical termination resulted in a significant deferral of depreciation deductions that were otherwise allowable in computing the taxable income of the Partnership’s unitholders for the period February 23, 2016 through December 31, 2016. The Partnership provided a single Schedule K-1 to each unitholder reflecting the unitholder’s taxable income for the full calendar year.

Based on management’s analysis, the Partnership did not have any uncertain tax positions as of December 31, 2017 .


9.	Related Party Transactions

In the ordinary course of business, the Partnership engages in transactions with EQT and its affiliates, including but not limited to, gathering, compression and water services agreements. For periods prior to the Mergers, related parties included Rice Energy and certain of its subsidiaries. Following the consummation of the Mergers, related parties included EQT and certain of its subsidiaries.

Omnibus Agreement

On December 22, 2014, upon completion of the Partnership’s IPO, the Partnership entered into an omnibus agreement with Midstream Management, Rice Energy and other affiliates (the Initial Omnibus Agreement). Pursuant to the Initial Omnibus Agreement, Rice Energy performed centralized corporate and general and administrative services for the Partnership, such as financial and administrative, information technology, legal, health, safety and environmental, human resources, procurement, engineering, business development, investor relations, insurance and tax. In exchange, the Partnership reimbursed Rice Energy for the expenses incurred in providing these services, except for any expenses associated with Rice Energy’s long-term incentive programs. On the Merger Date, in connection with the completion of the Mergers, the Partnership, EQT and other affiliates entered into an Amended and Restated Omnibus Agreement (the Amended Omnibus Agreement), with substantially the same terms as the Initial Omnibus Agreement.

The expenses for which the Partnership reimburses EQT and its subsidiaries related to corporate and general and administrative services may not necessarily reflect the actual expenses that the Partnership would incur on a stand-alone basis. The Partnership is unable to estimate what the costs would have been with an unrelated third party.


10.	Financial Information by Business Segment

The Partnership operates in two business segments: (i) gathering and compression and (ii) water services. Business segments are evaluated for their contribution to the Partnership’s consolidated results based on operating income. Other income and expenses, interest and income taxes are managed on a consolidated basis. There were no inter-segment transactions during any of the periods presented. The segment accounting policies are the same as those described in Note 1 to these consolidated financial statements. The operating results and assets of the Partnership’s reportable segments were as follows for each respective period.



	Successor
	Period from November 13, 2017 to December 31, 2017
(in thousands)	Gathering and Compression		Water Services		Consolidated Total
Total operating revenues	$	30,614	$	13,605	$	44,219
Total operating expenses	8,814		9,460		18,274
Operating income	$	21,800	$	4,145	$	25,945

Segment assets	$	2,640,682	$	208,331	$	2,849,013
Depreciation expense	$	3,965	$	3,515	$	7,480
Capital expenditures for segment assets	$	28,320	$	6,233	$	34,553



	Predecessor
	Period from January 1, 2017 to November 12, 2017
(in thousands)	Gathering and Compression		Water Services		Consolidated Total
Total operating revenues	$	167,492	$	82,982	$	250,474
Total operating expenses	46,743		40,253		86,996
Operating income	$	120,749	$	42,729	$	163,478

Depreciation expense	$	11,324	$	15,096	$	26,420
Capital expenditures for segment assets	$	113,373	$	10,394	$	123,767



	Predecessor
	Year Ended December 31, 2016
(in thousands)	Gathering and Compression		Water Services		Consolidated Total
Total operating revenues	$	132,099	$	69,524	$	201,623
Total operating expenses	38,951		35,730		74,681
Operating income	$	93,148	$	33,794	$	126,942

Segment assets	$	1,260,681	$	138,536	$	1,399,217
Depreciation expense	$	10,840	$	14,330	$	25,170
Capital expenditures for segment assets	$	113,033	$	8,054	$	121,087



	Predecessor
	Year Ended December 31, 2015
(in thousands)	Gathering and Compression		Water Services		Consolidated Total
Total operating revenues	$	77,211	$	37,248	$	114,459
Total operating expenses	28,326		24,097		52,423
Operating income	$	48,885	$	13,151	$	62,036

Segment assets	$	547,810	$	141,980	$	689,790
Depreciation expense	$	6,310	$	10,089	$	16,399
Capital expenditures for segment assets	$	149,706	$	98,757	$	248,463


11.	Quarterly Financial Information (Unaudited)

The Partnership’s quarterly financial information for the years ended December 31, 2017 and 2016 is as follows (in thousands, except per unit data):



	Predecessor								Successor
Year ended December 31, 2017: ⁽¹⁾	First quarter		Second quarter		Third quarter		Period from October 1 to November 12		Period from November 13 to December 31
Operating revenues	$	62,750	$	72,377	$	81,701	$	33,646	$	44,219
Operating expenses	22,154		25,363		27,054		12,424		18,274
Operating income	40,596		47,014		54,647		21,222		25,945
Net income	$	37,615	$	44,060	$	51,454	$	19,710	$	25,134
Net income per limited partner unit - basic	$	0.36	$	0.42	$	0.48	$	0.18	$	0.23
Net income per limited partner unit - diluted	$	0.36	$	0.42	$	0.48	$	0.18	$	0.23



	Predecessor
Year ended December 31, 2016: ⁽¹⁾	First quarter		Second quarter		Third quarter		Fourth quarter ⁽²⁾
Operating revenues	$	54,543	$	46,547	$	41,067	$	59,466
Operating expenses	18,926		17,547		15,531		22,677
Operating income	35,617		29,000		25,536		36,789
Net income	$	34,426	$	27,936	$	24,989	$	34,529
Net income per limited partner unit - basic	$	0.49	$	0.38	$	0.30	$	0.33
Net income per limited partner unit - diluted	$	0.48	$	0.38	$	0.30	$	0.33


(1)	The sum of quarterly data in some cases may not equal the yearly total due to rounding.


(2)	Includes the results of the Vantage Midstream Entities for the period from October 19, 2016 to December 31, 2016.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of management of Midstream Management, including Midstream Management's Principal Executive Officer and Principal Financial Officer, an evaluation of RMP's disclosure controls and procedures (as defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)), was conducted as of the end of the period covered by this report. Based on that evaluation, the Principal Executive Officer and Principal Financial Officer of Midstream Management concluded that RMP's disclosure controls and procedures were effective as of the end of the period covered by this report.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter of 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

The management of Midstream Management is responsible for establishing and maintaining adequate internal control over financial reporting. RMP's internal control system is designed to provide reasonable assurance to the management and Board of Directors of Midstream Management regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Accordingly, even effective controls can provide only reasonable assurance with respect to financial statement preparation and presentation.

The management of Midstream Management assessed the effectiveness of RMP's internal control over financial reporting as of December 31, 2017. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (2013). Based on this assessment, management concluded that RMP maintained effective internal control over financial reporting as of December 31, 2017.

Ernst & Young LLP (Ernst & Young), the independent registered public accounting firm that audited RMP's consolidated financial statements, has issued an attestation report on RMP's internal control over financial reporting. Ernst & Young's attestation report on RMP's internal control over financial reporting appears in Part II, Item 8 of this Annual Report on Form 10-K and is incorporated by reference herein.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Management of Rice Midstream Partners LP

Rice Midstream Partners LP (the Partnership, RMP, we, us, or like terms) are managed and operated by the Board of Directors (the Board) and executive officers of our general partner, Rice Midstream Management LLC (Midstream Management or our general partner). As a result of the Mergers, EQT became the indirect parent of our general partner and an indirect limited partner of us. Through its ownership and control of our general partner, EQT Corporation (EQT) appoints the directors of our general partner.

All of our officers and certain of our directors are also officers and/or directors of EQT and EQT Midstream Services, LLC (the EQM General Partner), the general partner of EQT Midstream Partners, LP (EQM), and certain of our officers and directors are also officers and/or directors of EQT GP Services, LLC (the EQGP General Partner), the general partner of EQT GP Holdings, LP (EQGP). EQT also controls and appoints the directors of the EQM General Partner and the EQGP General Partner. Neither our general partner nor its Board of Directors is elected by our unitholders and neither will be subject to re-election in the future. Our unitholders will not be entitled to directly or indirectly participate in our management or operations. Our general partner owes certain contractual duties to our unitholders as well as a fiduciary duty to its owners.

Director Independence

Our general partner has nine directors. The New York Stock Exchange (NYSE) does not require a listed publicly traded partnership such as ours to have a majority of independent directors on the Board of Directors of our general partner or to establish a compensation committee or a nominating committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act.

Board of Directors

In evaluating director candidates, EQT assesses whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that is likely to enhance the Board’s ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the Board to fulfill their duties.

All of the executive officers of our general partner listed below allocate their time between managing our business and affairs and the business and affairs of EQT and its affiliates, including EQM, the EQM General Partner, EQGP and the EQGP General Partner. The amount of time that our executive officers will devote to our business and the business of EQT and its affiliates, including EQM, the EQM General Partner, EQGP and the EQGP General Partner, will vary in any given year based on a variety of factors. Our executive officers intend, however, to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs.

As a result of the Mergers, EQT provides customary management and general administrative services to us pursuant to an amended and restated omnibus agreement. We reimburse EQT for all expenses incurred by EQT or its affiliates (or payments made on our behalf) in conjunction with its provision of general and administrative services to us, including but not limited to, our publicly traded partnership expenses and an allocated portion of the compensation expense of the executive officers and other employees of EQT and its affiliates who perform general and administrative services for us or on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, 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. Please see “Agreements with Affiliates—Omnibus Agreement” under “Item 13. Certain Relationships and Related Transactions and Director Independence.”

Board’s Role in Risk Oversight

Under the Audit Committee’s charter, it is required to discuss with management and the Partnership’s independent auditor the Partnership’s major risk exposures and the policies management has implemented to monitor and control such exposures, including the Partnership’s financial risk exposures and risk management policies.

Governance Principles

RMP has adopted a code of business conduct and ethics applicable to all directors, officers, employees and other personnel of RMP and its subsidiaries, as well as RMP’s suppliers, vendors, agents, contractors and consultants. The code of business conduct and ethics, along with RMP’s corporate governance guidelines and Audit Committee charter, are posted on

RMP’s website, www.ricemidstream.com (accessible under the “Corporate Governance” caption of the “Investors” page), and a printed copy of any of these documents will be delivered free of charge on request by writing to the Corporate Secretary of our general partner by mail or courier service c/o Rice Midstream Management LLC, 625 Liberty Avenue, Suite 1700, Pittsburgh, Pennsylvania 15222, Attn: Corporate Secretary. RMP intends to satisfy the disclosure requirement regarding certain amendments to, or waivers from, provisions of its code of business conduct and ethics by posting such information on RMP’s website.

Executive Officers and Directors of Our General Partner

The following table sets forth the names, ages and titles of our directors and executive officers as of February 15, 2018. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the Board. Some of the current directors and all of the executive officers of our general partner also serve as executive officers and/or directors of EQT.



Name	Age	Position with Our General Partner
J.J. Ashcroft III	45	Director, Senior Vice President and Chief Operating Officer
L.B. Gardner	60	Director
S.C. Hildebrandt	53	Director
D.M. Leland	56	Director
J.H. Lytal	60	Director
R.J. McNally	47	Director, Senior Vice President and Chief Financial Officer
D.L. Porges	60	Chairman
S.T. Schlotterbeck	52	Director, President and Chief Executive Officer
J.S. Smith	45	Chief Accounting Officer
R.F. Vagt	70	Director

Set forth below is the description of the background of our directors and executive officers.

Mr. Ashcroft was appointed as a director and as Senior Vice President and Chief Operating Officer of Midstream Management in November 2017. Mr. Ashcroft has also served as Senior Vice President and Chief Operating Officer of the EQM General Partner since August 2017 and has served as Senior Vice President, EQT Corporation and President, Midstream since August 2017. Prior to joining EQT, Mr. Ashcroft was most recently the Chief Executive Officer of Gulf Oil LP (a distributor of fuel products and lubricants) from September 2015 to June 2017; the Chief Operating Officer of JP Energy Partners, LP (an operator of a diversified portfolio of midstream assets including crude oil pipelines and storage, refined product terminals and storage, and natural gas liquids (NGLs) distribution and sales capabilities) from May 2014 to August 2015; and President of Buckeye Partners, LP’s (a provider of midstream logistics solutions, primarily consisting of the transport, storage, processing and marketing of liquid petroleum products) Natural Gas Storage, Development & Logistics and Energy Services business units from January 2012 to May 2014. Mr. Ashcroft has also served as a director of the EQM General Partner since August 2017.

Mr. Ashcroft brings extensive midstream energy industry senior management and operational experience to the Board, having served as Chief Executive Officer and in other senior management roles with each of Gulf Oil LP, JP Energy Partners, LP and Buckeye Partners, LP. Following a distinguished military career with the United States Marine Corps, Mr. Ashcroft began his midstream energy industry career with Colonial Pipeline Company, L.P. Mr. Ashcroft’s experiences enable him to provide valuable insight to the Board with respect midstream company operations and strategy and business management issues.

Mr. Gardner was appointed as a director of Midstream Management in November 2017. Mr. Gardner has served as a director of the EQM General Partner and the EQGP General Partner since January 2012 and January 2015, respectively. Mr. Gardner is currently the General Counsel and Vice President, External Affairs of EQT and has held such position since April 2008. In his current role with EQT, Mr. Gardner oversees legal and external affairs, which includes the safety and environmental, governmental relations and corporate communications functions. Prior to joining EQT in 2003, Mr. Gardner was a partner in the Houston and Austin, Texas offices of Brown, McCarroll & Oaks Hartline, General Counsel to General Glass International Corp., a privately held glass manufacturing and trading company, and Senior Counsel, Employment Law with Northrop Grumman Corporation (formerly TRW, Inc.). Mr. Gardner’s experiences enable him to provide insight to the Board with respect to legal and external affairs issues, along with providing valuable perspectives with respect to business management and corporate governance issues.

Ms. Hildebrandt has served as a director of Midstream Management since March 2016 and currently serves as a member of the Conflicts Committee. Ms. Hildebrandt has served as Senior Vice President, General Counsel and Secretary of Archrock, Inc. (formerly named Exterran Holdings, Inc.) (Archrock) and Senior Vice President and General Counsel of Archrock GP LLC, the managing general partner of Archrock Partners, L.P., since August 2017. Prior to joining Archrock, Ms. Hildebrandt was a partner of global business law firm Norton Rose Fulbright’s Houston office from February 2015 to June 2017. She also previously worked as the Secretary, Senior Vice President, and General Counsel of publicly traded pipeline and infrastructure company and consumer energy service provider Enterprise Products Partners L.P. (Enterprise) from May 2010 to December 2014 and held various other roles at Enterprise, including Assistant Secretary, Vice President, and Deputy General Counsel from September 2004 to May 2010. She served as Secretary, Senior Vice President, and Chief Legal Officer at Duncan Energy Partners L.P. until its merger with Enterprise from April 2010 to September 2011 and was an attorney for El Paso Corporation / GulfTerra Energy Partners until its merger with Enterprise from 2001 to 2004 and Texaco, Inc. from 1989 to 2001. Ms. Hildebrandt has served as a member of the Boards of Directors of Archrock GP LLC and WildHorse Resource Development Corporation since August 2017 and December 2017, respectively, and currently serves as a member of the advisory council of the Kay Bailey Hutchison Center for Energy, Law & Business at the University of Texas. She also served on the Board of Directors of TRC Companies Inc. from December 2014 to June 2017. Ms. Hildebrandt is a former governing director of the Houston Symphony Society. Ms. Hildebrandt has a BS in Foreign Service from Georgetown University and a JD from Tulane University Law School. She is admitted to the state bars of Texas and Louisiana.

Ms. Hildebrandt brings extensive experience in the midstream energy industry and legal background that provides significant contributions to the Board.

Mr. Leland has served as a director of Midstream Management since December 2014 and currently serves as Chairman of the Audit Committee, a member of the Conflicts Committee and, effective as of November 13, 2017, the Presiding Director of the Board. Mr. Leland has served on the Audit Committee of the Board of Directors of Kayne Anderson Acquisition Corp. since March 2017 and on the Board of Directors of Deltic Timber Corporation (Deltic) since June 2016 and as interim Chief Executive Officer of Deltic from October 2016 to March 2017. Mr. Leland served on the Board of Directors of the general partner of Oiltanking Partners, L.P. from June 2012 until February 2015 and on the Board of Directors of KiOR, Inc. from June 2013 until March 2015. Mr. Leland served as Executive Vice President of El Paso Corporation (El Paso) and President of El Paso’s midstream business unit from October 2009 to May 2012, and as director of El Paso Pipeline Partners, L.P. from its formation in 2007 to May 2012. Mr. Leland also previously served as Executive Vice President and Chief Financial Officer of El Paso from August 2005 to November 2009. He served as Executive Vice President of El Paso Exploration & Production Company from January 2004 to August 2005, and as Chief Financial Officer and a director from April 2004 to August 2005. Mr. Leland served as Senior Vice President and Chief Operating Officer of the general partner of GulfTerra Energy Partners, L.P. from January 2003 to December 2003, and as Senior Vice President and Controller from July 2000 to January 2003.

Mr. Leland brings extensive operational and financial experience in the midstream energy industry, as well as experience on the boards of numerous publicly traded energy companies, that provide significant contributions to the Board.

Mr. Lytal has served as a director of Midstream Management since August 2015 and currently serves as Chairman of the Conflicts Committee and a member of the Audit Committee. Mr. Lytal has served on the Board of Directors of SemGroup Corporation since November 2011 and on the Board of Directors of Archrock since April 2015. Mr. Lytal also served on the Board of Directors of Azure Midstream GP, LLC, the general partner of Azure Midstream Partners, LP from September 2013 to May 2017. Since April 2007, Mr. Lytal has also served as a senior advisor to Global Infrastructure Partners, a New York based partnership that invests in infrastructure assets globally. From 1994 to 2004, Mr. Lytal was President of Leviathan Gas Pipeline Partners, which later became El Paso Energy Partners, and then Gulfterra Energy Partners, where he served on the Board of Directors. In 2004, Gulfterra Energy Partners merged with Enterprise Products Partners, one of the largest publicly traded energy partnerships in the United States, where Mr. Lytal served as Executive Vice President until 2009. From 1998 to 2008, he was directly involved in the development of over $3 billion in offshore platform and oil and gas pipeline projects. Having entered the energy industry in 1980, Mr. Lytal’s business experience includes midstream mergers, acquisitions and master limited partnership drop-downs, as well as onshore midstream and deepwater asset development and management. He graduated from the University of Texas at Austin with a Bachelor of Science degree in petroleum engineering.

Mr. Lytal brings extensive operational, managerial and financial experience in the midstream energy industry, as well as experience on the boards of numerous publicly traded energy companies, that provide significant contributions to the Board.

Mr. McNally was appointed as a director and as Senior Vice President and Chief Financial Officer of Midstream Management in November 2017. Mr. McNally has served as a director and as Senior Vice President and Chief Financial Officer of the EQM General Partner and the EQGP General Partner, and as Senior Vice President and Chief Financial Officer of EQT, in each case since March 2016. Mr. McNally served as Executive Vice President and Chief Financial Officer of Precision Drilling Corporation (a publicly traded drilling services company) from July 2010 to March 2016.

Mr. McNally brings deep energy industry management, finance and operational experience to the Board, having served as Executive Vice President and Chief Financial Officer of Precision Drilling Corporation from July 2010 to March 2016. Mr. McNally also brings strong capital markets and mergers and acquisitions experience to the Board, having previously served as an investment banker with Simmons & Company International. Mr. McNally began his career with Schlumberger Limited, working in operations and sales. Mr. McNally’s experiences enable him to provide insight to the Board with respect to accounting matters, financial markets, financing transactions, mergers and acquisitions and energy company operations.

Mr. Porges has served as Chairman of the Board of Midstream Management since November 2017, and currently serves as the Executive Chairman of EQT and has held such position since March 2017. Mr. Porges was Chairman and Chief Executive Officer of EQT from December 2015 through February 2017, and was Chairman, President and Chief Executive Officer of EQT from May 2011 to December 2015. Mr. Porges has also served as Chairman of the Boards of Directors of the EQGP General Partner and the EQM General Partner since January 2015 and January 2012, respectively. Mr. Porges served as President and Chief Executive Officer of the EQM General Partner from January 2012 through February 2017 and as President and Chief Executive Officer of the EQGP General Partner from January 2015 through February 2017. As previously disclosed in EQT’s Form 8-K filed with the Securities and Exchange Commission (the SEC) on January 18, 2018, Mr. Porges intends to retire from his position as Executive Chairman of EQT on February 28, 2018. Following that time, he will continue to serve as a non-executive Chairman of EQT’s Board of Directors.

Mr. Porges brings extensive business, leadership, management and financial experience to the Board. Mr. Porges has served in a number of senior management positions with EQT since joining EQT as Senior Vice President and Chief Financial Officer in 1998. He has also served as a member of EQT’s Board of Directors since May 2002. Prior to joining EQT, Mr. Porges held various senior positions within the investment banking industry and also held several managerial positions with Exxon Corporation (now, Exxon Mobil Corporation, an international oil and gas company). Mr. Porges served on the Board of Directors of Westport Resources Corp. (an oil and natural gas production company that is now part of Anadarko Petroleum Corporation) from April 2000 through 2004. Mr. Porges' strong financial and industry experience enables Mr. Porges to provide unique and valuable perspectives on most issues facing RMP.

Mr. Schlotterbeck has served as a director and as President and Chief Executive Officer of Midstream Management since November 2017 and as President and Chief Executive Officer of EQT, the EQM General Partner and the EQGP General Partner since March 2017. Prior to being elected as Chief Executive Officer of EQT, Mr. Schlotterbeck served as President, EQT Corporation and President, Exploration and Production from December 2015 to February 2017; Executive Vice President, EQT Corporation and President, Exploration and Production from December 2013 to December 2015; and Senior Vice President, EQT Corporation and President, Exploration and Production from April 2010 to December 2013. Mr. Schlotterbeck has also served as a director of EQT since January 2017, a director of the EQM General Partner since January 2017, and a director of the EQGP General Partner since January 2015.

Mr. Schlotterbeck brings extensive business, senior management and natural gas industry experience to the Board, having held various senior management and petroleum engineering positions within the energy industry over the past 29 years. Mr. Schlotterbeck led EQT's production business from 2008 until his promotion to Chief Executive Officer. In his role, Mr. Schlotterbeck was responsible for, among other things, executing EQT's natural gas production growth strategy. Mr. Schlotterbeck's extensive industry knowledge and senior management experience enables him to bring valuable perspectives regarding the natural gas industry and business management issues.

Ms. Smith was appointed as Chief Accounting Officer of Midstream Management in November 2017. Ms. Smith has also served as the Chief Accounting Officer of the EQM General Partner, the EQGP General Partner and EQT since September 2016. Ms. Smith served as Vice President and Controller of EQT’s midstream and commercial businesses from March 2013 to September 2016; and as Vice President and Controller of EQT’s midstream business from January 2013 to March 2013.

Mr. Vagt has served as a director of Midstream Management since January 2014 and currently serves as a member of the Audit Committee. He served as the Chairman of the Board of Midstream Management from December 2014 to November 2017. He also served as the Chairman of Rice Energy’s Board of Directors from January 2014 until EQT’s acquisition of Rice Energy in November 2017, during which time he also served as Chairman of the Health, Safety and Environmental and Nominating and Governance Committees and a member of Rice Energy’s Audit Committee. Mr. Vagt joined EQT’s Board of Directors in November 2017 and currently serves on the Corporate Governance Committee. Mr. Vagt has served as a member of the Board of Directors of Kinder Morgan, Inc. since May 2012, where he serves as Chairman of the Environmental, Health and Safety Committee and as a member of the Audit Committee. Mr. Vagt served as a member of the Board of Directors of El Paso Corporation from May 2005 until June 2012, where he was a member of the Compensation and Health, Safety and Environmental Committees. From January 2008 until January 2014, Mr. Vagt was also the President of The Heinz Endowments. Prior to his tenure at The Heinz Endowments, Mr. Vagt served as President of Davidson College from July 1997 to August 2007. Mr. Vagt served as President and Chief Operating Officer of Seagull Energy Corporation from 1996 to 1997.

From 1992 to 1996, he served as President, Chairman and Chief Executive Officer of Global Natural Resources. Mr. Vagt served as President and Chief Operating Officer of Adobe Resources Corporation from 1989 to 1992. Prior to 1989, he served in various positions with Adobe Resources Corporation and its predecessor entities.

Mr. Vagt’s professional background in both the public and private sectors make him an important advisor and member of our Board. Mr. Vagt brings to the Board operations and management expertise in both the public and private sectors. In addition, Mr. Vagt provides the Board with diversity of perspective gained from service as President of The Heinz Endowments, as well as from service as the President of an independent liberal arts college.

Meetings of Non-Management Directors and Communications with Directors

At least annually, the independent directors of our general partner meet in executive session without management participation or participation by non-independent directors. Mr. Leland, as the Chairman of the Audit Committee, serves as the presiding director for such executive sessions. The presiding director may be contacted by mail or courier service c/o Rice Midstream Management LLC, 625 Liberty Avenue, Suite 1700, Pittsburgh, Pennsylvania 15222, Attn: Presiding Director or by email at presidingdirector@ricemidstream.com.

Committees of the Board of Directors

The Board of Directors of our general partner has two standing committees: an Audit Committee and a Conflicts Committee. We do not have a compensation committee or a nominating and corporate governance committee.

Audit Committee

Rules implemented by the NYSE and SEC require us to 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. As required by the rules of the SEC and listing standards of the NYSE, the audit committee consists solely of independent directors. Our Audit Committee currently consists of Messrs. Leland (Chairman), Lytal and Vagt, each of whom is independent under the rules of the SEC and the NYSE. SEC rules also require that a public company disclose whether or not its audit committee has an “audit committee financial expert” as a member. An “audit committee financial expert” is defined as a person who, based on his or her experience, possesses the attributes outlined in such rules. The Board believes that each of Messrs. Leland and Vagt satisfies the definition of “audit committee financial expert” as such term is defined under the SEC’s regulations. The designation does not impose upon Messrs. Leland and Vagt any duties, obligations or liabilities that are greater than those generally imposed on them as members of the Audit Committee and the Board. The Board also believes that each of Messrs. Leland, Lytal and Vagt has the accounting or related financial management expertise required by NYSE rules.

The Audit Committee assists the Board in its oversight of the integrity of RMP’s financial statements and compliance with legal and regulatory requirements and corporate controls. The Audit Committee has the sole authority to retain and terminate RMP’s 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 RMP’s independent registered public accounting firm. The Audit Committee is also responsible for confirming the independence and qualifications of RMP’s independent registered public accounting firm.

Conflicts Committee

Messrs. Lytal (Chairman) and Leland and Ms. Hildebrandt serve on our Conflicts Committee and review specific matters that the Board believes may involve conflicts of interest and determines to submit to the Conflicts Committee for review. The Conflicts Committee will determine if the resolution of the conflict of interest is adverse to the interest of the Partnership. There is no requirement that our general partner seek the approval of the Conflicts Committee for the resolution of any conflict. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including EQT, EQGP and EQM, 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, along with other requirements in our partnership agreement. Any matters approved by the Conflicts Committee will be conclusively deemed to be approved by us and all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires that the directors and executive officers of our general partner and all persons who beneficially own more than 10% of our common units file initial reports of ownership and reports of changes in ownership of our common units with the SEC. As a practical matter, we assist the directors and executive officers of our general partner by monitoring transactions and completing and filing Section 16 reports on their behalf.

Based solely upon our review of copies of filings or written representations from the reporting persons, we believe that all reports for the executive officers and directors of our general partner and persons who beneficially own more than 10% of our common units that were required to be filed under Section 16(a) of the Exchange Act in 2017 were filed on a timely basis.

Item 11. Executive Compensation

Compensation Discussion and Analysis

RMP does not directly employ or pay any of the persons responsible for managing its business. RMP is managed and operated by the directors and officers of Midstream Management. Prior to the Mergers, Rice Energy employed and compensated all of the individuals who serviced RMP. Following the Mergers, EQT employs and compensates such individuals, including the current executive officers of Midstream Management. In all cases, these individuals devote (or devoted) such portion of their productive time to RMP’s business and affairs as is (was) required to manage and conduct RMP’s operations. RMP reimburses EQT (and previously reimbursed Rice Energy) for compensation for the employees of EQT (previously, Rice Energy) who provide (or provided) services to RMP pursuant to an allocation agreed upon between EQT (previously, Rice Energy) and RMP. Please read “Item 13. Certain Relationships and Related Transactions, and Director Independence - Agreements with EQT - Omnibus Agreement.”

The officers of Midstream Management discussed below as our named executive officers for 2017 are:


•	Steven T. Schlotterbeck, President and Chief Executive Officer;


•	Robert J. McNally, Senior Vice President and Chief Financial Officer;


•	Daniel J. Rice, IV, former Chief Executive Officer;


•	Grayson T. Lisenby, former Senior Vice President and Chief Financial Officer;


•	William E. Jordan, former Senior Vice President, General Counsel and Corporate Secretary; and


•	Robert R. Wingo, former Senior Vice President and Chief Operating Officer.

Messrs. Schlotterbeck and McNally (the EQT Executives) assumed their respective positions, and Messrs. Rice, Lisenby, Jordan, and Wingo (collectively, the Former Rice Executives) were terminated without cause from their positions, on November 13, 2017, concurrent with the closing of the Mergers.

The EQT Executives are also executive officers of EQT, the EQM General Partner and the EQGP General Partner. The Former Rice Executives were also executive officers of Rice Energy.

Neither RMP nor Midstream Management has a compensation committee. All decisions as to the compensation of the EQT Executives are made by the Management Development and Compensation Committee of the Board of Directors of EQT (the EQT MDC Committee). All decisions as to the compensation of the Former Rice Executives were made by the Compensation Committee of the Board of Directors of Rice Energy. Therefore, neither RMP nor Midstream Management has any policies or programs relating to compensation, and neither RMP nor Midstream Management make decisions relating to compensation, though from time to time the Board of Directors of Midstream Management may be asked to approve awards granted under the Rice Midstream Partners, LP 2014 Long-Term Incentive Plan. We expect any such future awards to be previously approved by the EQT MDC Committee as part of the executive’s total EQT compensation. None of the executive officers of Midstream Management have (or had) employment agreements with Midstream Management or RMP or are (or were) otherwise specifically compensated for their service as an executive officer of Midstream Management.

The amounts listed in the Summary Compensation Table below for the Former Rice Executives represent the amounts reimbursed by us to Rice Energy for the individuals’ efforts managing our business through November 12, 2017. The amounts listed in the Summary Compensation Table below for the EQT Executives represent the amounts reimbursed by us to EQT for the individuals’ efforts managing our business from and after November 13, 2017.

A discussion of EQT’s compensation policies and programs as they apply to the EQT Executives and detailed information regarding all compensation paid or payable by EQT to the EQT Executives, a portion of which is included in our Summary Compensation Table will be set forth in EQT’s Proxy Statement for its 2018 Annual Shareholders Meeting or in an amendment to EQT’s Annual Report on Form 10-K for the year ended December 31, 2017 (in either case, EQT’s Disclosure Document). This Compensation Discussion and Analysis does not contain a discussion of Rice Energy’s compensation policies and programs as they applied to the Former Rice Executives because Rice Energy, which made all decisions as to the compensation of the Former Rice executives, ceased to exist as a result of the Mergers.

EQT’s Disclosure Document will be available upon its filing (expected not later than April 30, 2018) on the SEC’s website at www.sec.gov and on EQT’s website at www.eqt.com by clicking on the “Investors” link on the main page followed by the “SEC Filings” link. EQT’s Disclosure Document will also be available free of charge upon request by a unitholder to the Corporate Secretary of Midstream Management by mail or courier service c/o Rice Midstream Services, LLC, 625 Liberty Avenue, Suite 1700, Pittsburgh, Pennsylvania 15222, Attn: Corporate Secretary.

Compensation Committee Report

Neither we nor our general partner has a compensation committee. The board of directors of our general partner has reviewed and discussed the Compensation Discussion and Analysis set forth above and based on this review and discussion has approved it for inclusion in this Annual Report on Form 10-K.

The board of directors of Rice Midstream Services, LLC includes:

David L. Porges

Jeremiah J. Ashcroft III

Lewis B. Gardner

Stephanie C. Hildebrandt

D. Mark Leland

James H. Lytal

Robert J. McNally

Steven T. Schlotterbeck

Robert F. Vagt

Summary Compensation Table

The Summary Compensation Table below reflects the total compensation of the principal executive officer (including Daniel J. Rice IV, who was the principal executive officer until the Mergers and Steven T. Schlotterbeck who was the principal executive officer for the balance of the year), the principal financial officer (including Grayson T. Lisenby who was the principal financial officer until the Mergers and Robert J. McNally who was the principal financial officer for the balance of the year), William E. Jordan who was the Senior Vice President, General Counsel and Corporate Secretary until the Mergers and Robert R. Wingo who was the Senior Vice President and Chief Operating Officer until the Mergers (the named executive officers) allocated to us pursuant to the Initial Omnibus Agreement and the Amended Omnibus Agreement (each as defined in Note 9 to the Consolidated Financial Statements), as applicable. Messrs. Schlotterbeck and McNally are referred to as the “EQT Executives” and Messrs. Rice, Lisenby, Jordan and Wingo are referred to as the “Former Rice Executives.” The compensation information set forth in this Item 11, “Executive Compensation,” was provided by EQT.



Name and Principal Position (1)	Year	Salary ($)(2)	Bonus ($)	Stock Awards ($)(3)	Option Awards ($)(3)	Non-Equity Incentive Plan Compensation ($)(4)	All Other Compensation ($)(5)	Total ($)
S.T. Schlotterbeck President and Chief Executive Officer	2017	18,515	—	—	—	52,603	5,420	76,538
S.T. Schlotterbeck President and Chief Executive Officer
R.J. McNally Senior Vice President and Chief Financial Officer	2017	12,263	—	—	—	19,068	2,847	34,178

D.J. Rice IV Former Chief Executive Officer	2017	76,923	—	—	—	104,474	2,128	183,525
	2016	80,000	—	—	—	114,240	478	194,718
	2015	40,000	—	—	—	55,897	1,590	97,487
G.T. Lisenby Former Senior Vice President and Chief Financial Officer	2017	76,923	—	—	—	104,474	3,600	184,997
	2016	80,000	—	—	—	114,240	1,435	195,675
	2015	40,000	—	—	—	55,897	—	95,897
W.E. Jordan Former Senior Vice President, General Counsel and Corporate Secretary	2017	70,269	—	—	—	94,976	3,600	168,845
	2016	73,000	—	—	—	96,018	1,452	170,470

R.R. Wingo Former Senior Vice President and Chief Operating Officer	2017	159,808	—	—	—	237,440	9,000	406,248
	2016	175,000	—	—	—	234,728	3,646	413,374
	2015	137,500	—	—	—	76,150	7,950	221,600


(1)	No other executive officers who served during 2017 had more than $100,000 of their compensation allocated to us in 2017.


(2)	For the EQT Executives, this column represents the portion of base salary paid to the executive by EQT following the Mergers that was reimbursable by us under the Amended Omnibus Agreement. For the Former Rice Executives, this column represents the portion of the base salary paid to the executive by Rice Energy prior to the Mergers that was reimbursable by us under the Initial Omnibus Agreement.


(3)	No awards were granted under the LTIP to the named executive officers in 2017. None of the awards granted to the Former Rice Executives under the Rice Energy Inc. 2014 Long-Term Incentive Plan or the EQT Executives under the EQT Corporation 2014 Long-Term Incentive Plan were reimbursable by us.

(4)

For the EQT Executives, this column reflects the dollar value of annual incentive compensation earned under the EQT Executive STIP (as defined and described under the caption “Narrative Disclosure to Summary Compensation Table and 2017 Grants of Plan-Based Awards Table” below) that was reimbursable by us under the Amended Omnibus Agreement. See “Non-Equity Incentive Plan Compensation - EQT Executive Short-Term Incentive Plan (EQT Executive STIP)” under the caption “Narrative Disclosure to Summary Compensation Table and 2017 Grants of Plan-Based Awards Table” below for further discussion of the EQT Executive STIP for the 2017 plan year. For the Former Rice Executives, for 2017, this column reflects the dollar value of the annual bonuses allocated to us for the ten and a half months of service provided by the Former Rice Executives. See “Non-Equity Incentive Plan Compensation - Rice Energy Inc. Annual Incentive Bonus Plan (Rice Annual Bonus Plan)” under the caption “Narrative Disclosure to Summary Compensation Table and 2017 Grants of Plan-Based Awards Table” below for further discussion of the Rice Annual Bonus Plan for the 2017 plan year.


(5)	For the EQT Executives, this column includes the portion reimbursable by us under the Amended Omnibus Agreement of EQT’s contributions to the EQT Corporation 401(k) plan and 2006 Payroll Deduction and Contribution Program. Once 401(k) contributions for the EQT Executives reach the maximum level permitted under the EQT Corporation 401(k) plan, EQT contributions are continued

on an after-tax basis under the 2006 Payroll Deduction and Contribution Program through an annuity program offered by Fidelity Investments Life Insurance Co. EQT also contributes an amount equal to 11% of the executive’s annual incentive awards to such program. For the Former Rice Executives, this column reflects the portion reimbursable by us under the Initial Omnibus Agreement of matching contributions made by Rice Energy to the Rice Energy Inc. 401(k) plan.

No perquisites were allocated to us in 2017.

2017 Grants of Plan-Based Awards Table



			Estimated Future Payouts Under Non-Equity Incentive Plan Awards
Name	Type of Award ($)(1)	Percentage of Award Reimbursed (%)	Threshold ($)(2)	Target ($)(2)	Maximum ($)(2)
S.T. Schlotterbeck	ESTIP	20	—	22,356	131,507
R.J. McNally	ESTIP	20	—	9,370	131,507
D.J. Rice IV	RAIB	20	35,200	70,400	140,800
G.T. Lisenby	RAIB	20	35,200	70,400	140,800
W.E. Jordan	RAIB	20	32,000	64,000	128,000
R.R. Wingo	RAIB	50	80,000	160,000	320,000


(1)	Type of Award:

ESTIP = EQT Executive STIP

RAIB = Rice Annual Bonus Plan

(2)

For the EQT Executives, these columns reflect the amount we would be allocated based upon the target and maximum amounts under the EQT Executive STIP for the 2017 plan year under the Amended Omnibus Agreement. Under the EQT Executive STIP, a formula based on adjusted 2017 EQT EBITDA compared to EQT’s business plan establishes the maximum payment from which the EQT MDC Committee typically exercises its discretion downward in determining the actual payment. The payout amounts could range from no payment, to the percentage of base salary identified as the target annual incentive award (target), to $5 million (maximum). See “Non-Equity Incentive Plan Compensation - EQT Executive Short-Term Incentive Plan (EQT Executive STIP)” under the caption “Narrative Disclosure to Summary Compensation Table and 2017 Grants of Plan-Based Awards Table” below for further discussion of the EQT Executive STIP for the 2017 plan year. For the Former Rice Executives, the amounts in these columns reflect the amount we would be allocated based upon the threshold, target and maximum values of the 2017 grants under the Rice Annual Bonus Plan. See “Non-Equity Incentive Plan Compensation - Rice Energy Inc. Annual Incentive Bonus Plan (Rice Annual Bonus Plan)” under the caption “Narrative Disclosure to Summary Compensation Table and 2017 Grants of Plan-Based Awards Table” below for further discussion of the Rice Annual Bonus Plan for the 2017 plan year.

NARRATIVE DISCLOSURE TO SUMMARY COMPENSATION TABLE AND 2017 GRANTS OF PLAN-BASED AWARDS TABLE

Set forth below is a discussion of the material elements of compensation paid to our named executive officers as reflected in the Summary Compensation Table and the 2017 Grants of Plan-Based Awards Table. This discussion should be read in conjunction with the Summary Compensation Table and the 2017 Grants of Plan-Based Awards Table above.

Base Salary

The base salary for each named executive officer reflected in the Summary Compensation Table above is the base salary actually earned and allocated to us under the Amended Omnibus Agreement and Initial Omnibus Agreement, as applicable.

Non-Equity Incentive Plan Compensation - EQT Executive Short-Term Incentive Plan (EQT Executive STIP)

The EQT Executives participated in the EQT Executive STIP. Before or at the start of each year, the EQT MDC Committee establishes the performance measure for determining awards under the EQT Executive STIP. This performance measure establishes the maximum annual incentive award that the EQT MDC Committee may approve as “performance-based compensation”, subject to the shareholder approved individual limit set forth in the EQT Executive STIP, but does not set an expectation for the amount of annual incentive that will actually be paid. The EQT MDC Committee is permitted to exercise,

and has generally exercised, downward discretion in determining the actual payout under the annual incentive plan. The EQT MDC Committee may not exercise upward discretion. The performance measure approved for the EQT Executive STIP for the 2017 plan year was adjusted 2017 EQT EBITDA (a non-GAAP financial measure), compared to EQT’s 2017 business plan, as set forth in the following table. See Exhibit 99 to this Annual Report on Form 10-K for a reconciliation of adjusted 2017 EQT EBITDA to EQT’s net income, the most directly comparable GAAP financial measure, as well as other important disclosures regarding non-GAAP financial measures.



ADJUSTED 2017 EQT EBITDA COMPARED TO BUSINESS PLAN	PERCENTAGE OF ADJUSTED 2017 EQT EBITDA AVAILABLE FOR EQT EXECUTIVE OFFICER 2017 ANNUAL INCENTIVE AWARDS
At or above plan	2	%
5% below plan	1.5	%
25% below plan	1	%
Greater than 25% below plan	No bonus

The percentage of adjusted 2017 EQT EBITDA available for eligible executive officer annual incentives was interpolated between levels and capped at 2%. Actual adjusted 2017 EQT EBITDA of $1,537 million exceeded plan by approximately 0.1%, which allowed the EQT MDC Committee to award annual incentives to EQT’s eight eligible executive officers in an aggregate amount of $30.7 million, subject to a $5 million cap per executive officer. The EQT MDC Committee exercised its discretion to pay each eligible named executive officer a lesser amount based on the individual’s 2017 target award and 2017 performance on EQT, business unit and individual value drivers. See the Summary Compensation Table for the portion of each of the EQT Executive’s award under the EQT Executive STIP that was allocated to us pursuant to the Amended Omnibus Agreement.

The EQT Executive STIP provides that the annual awards will be paid in cash, subject to EQT MDC Committee discretion to pay in equity. The EQT MDC Committee typically considers settling awards in equity rather than cash only when an executive has not satisfied the applicable equity ownership guidelines.

Non-Equity Incentive Plan Compensation - Rice Energy Inc. Annual Incentive Bonus Plan (Rice Annual Bonus Plan)

The compensation committee of the Rice Energy board of directors (Rice Energy Compensation Committee) established annual bonus awards for the Former Rice Executives to reward performance against 2017 strategic goals. The awards provided for a range of pay-outs between 0% to 200% of the target opportunity, depending on Rice Energy’s results for the year relative to the performance measures.



Named Executive Officer		2017 Target Bonus
D.J. Rice, IV		$352,000
G.T. Lisenby		$352,000
W.E. Jordan		$320,000
R.R. Wingo		$320,000

The mix of 2017 award metrics included goals relating to net production (MMcfe per day, or MMcfe/d) (Net Production), exploration and production capital expenditures (E&P CapEx), midstream capital expenditures efficiency (Midstream CapEx), general and administrative expense (G&A), lease operating expense (LOE) and safety.

After determining the metrics described above, the Rice Energy Compensation Committee established relative weightings for each category as follows:



Metric	Percentage of Award
Net Production (MMcfe/d)	25	%
E&P CapEx	20	%
Midstream CapEx	20	%
G&A ($MM)	10	%
LOE ($/Mcfe)	5	%
Safety (% improvement)	20	%
Total	100	%

Threshold, target and maximum achievement paid out at 50%, 100%, and 200%, respectively. See the Summary Compensation Table for the portion of each of the Former Rice Executive’s award under the Rice Annual Bonus Plan that was allocated to us pursuant to the Initial Omnibus Agreement.

Retirement Benefits

The EQT Executives participate in employee benefit plans and arrangements sponsored by EQT, and the Former Rice Executives participated in employee benefit plans and arrangements sponsored by Rice Energy. We were allocated a portion of the 401(k) contributions made by EQT and Rice Energy, as applicable. See footnote 5 to the Summary Compensation Table for additional information. EQT provides full discussion of its plans and arrangements in its filings with the SEC, including its annual proxy statement relating to the annual meeting of the shareholders of EQT, which filings are available on the SEC’s website at www.sec.gov and on EQT’s website at www.EQT.com on the “SEC Filings” page under the “Investors Relations” tab. The Corporate Secretary of Midstream Management will also provide a copy to you free of charge upon request.

Outstanding Equity Awards at Fiscal Year-End

The named executive officers had no outstanding RMP equity awards as of December 31, 2017.

Option Exercises and Stock Vested

No RMP performance awards vested or RMP stock options were exercised by the named executive officers during 2017.

Potential Payments Upon Termination or Change of Control

We do not have any agreements with the named executive officers that provide for payment to them in the event of their resignation, retirement, or other termination in the event of a change of control. EQT maintains and has entered into certain agreements and plans with the EQT Executives that require EQT to provide compensation to the EQT Executives, among others, in the event of a termination of employment or a change of control of EQT. Rice Energy maintained and had entered into certain agreements and plans with the Former Rice Executives that required Rice Energy to provide compensation to the Former Rice Executives in the event of a termination of employment or a change of control of Rice Energy. No amounts were allocated to us in connection with the Mergers.

No payments would be due to the named executive officers upon a change of control of RMP on December 31, 2017 that was not also a change of control of EQT.

Descriptions of the circumstances which trigger payments and benefits, the benefits that would be provided, how payment and benefit levels are determined and the material conditions and obligations applicable to the receipt of payments or benefits in the event of a termination of employment or a change of control of EQT will be described in EQT’s Disclosure Document. EQT’s SEC filings are available on the SEC’s website at www.sec.gov and on EQT’s website at www.EQT.com on the “SEC Filings” page under the “Investors Relations” tab. The Corporate Secretary of Midstream Management will also provide a copy to you free of charge upon request.

Pay Ratio

RMP does not have any employees. The daily business operations of RMP are conducted by employees of EQT. The estimate of the relationship of the annual total compensation of Mr. Schlotterbeck, EQT’s Chief Executive Officer, and of the median of the annual total compensation of EQT’s employees, calculated in accordance with applicable SEC rules will be set forth in EQT’s Disclosure Document.

Director Compensation

Prior to the Mergers, officers of Rice Energy, and members of the Rice family who also served as directors of our general partner, did not receive additional compensation for such service. Messrs. Rice III, Rice IV, and Wingo did not receive additional compensation for serving as directors. After the Mergers, officers of EQT who also serve as directors of our general partner do not receive additional compensation for such service.

Generally, 2017 compensation for directors of our general partner consisted of (a) an annual cash retainer of $250,000 for the Chairman of the Board, $100,000 for Committee Chairmen, and $90,000 for all other directors, each of which was paid on a quarterly basis, and (b) an annual equity award valued at approximately $250,000 for the Chairman of the Board, $170,000 for Committee Chairmen, and $165,000 for all other directors.

During 2017, Messrs. Leland and Lytal and Ms. Hildebrandt were the only individuals who received compensation for their services as directors of our general partner. Mr. Vagt was eligible but declined to receive compensation for his service on the Board in 2017. The equity awards granted to Messrs. Leland and Lytal and Ms. Hildebrandt during 2017 were phantom units which will vest and be settled in our common units on the first anniversary of the date of grant, so long as they continue to provide services to us through that date.

In addition, each non-employee director is reimbursed for out-of-pocket expenses incurred in connection with attending Board and Committee meetings and is fully indemnified by us for actions associated with serving as a director to the fullest extent permitted under Delaware law.

The following table includes information regarding non-executive director compensation for our general partner for the year ended December 31, 2017.



2017 Director Compensation Table
Director ⁽¹⁾	Fees Earned or Paid in Cash ($)	Stock Awards ($) ⁽²⁾	Total ($)
R. F. Vagt	—	—	—
D.M. Leland	100,000	169,991	269,991
J.H. Lytal	100,000	169,991	269,991
S.C. Hildebrandt	90,000	165,012	255,012
D.J. Rice III	—	—	—


(1)	Messrs. Rice III, Rice IV and Wingo served as directors until the Mergers and did not receive additional compensation for serving as directors. Mr. Vagt did not receive any compensation for serving as a director during 2017. Messrs. Ashcroft, Gardner, McNally, Porges and Schlotterbeck did not receive additional compensation for serving as directors after the Mergers.


(2)	Amounts reflect the grant date fair value of phantom units granted on May 31, 2017 to Messrs. Leland and Lytal and Ms. Hildebrandt, calculated in accordance with FASB ASC Topic 718. The amounts are calculated by multiplying the number of units granted (Mr. Leland 6,964, Mr. Lytal 6,964 and Ms. Hildebrandt 6,760) by the closing price of units on the day prior to the date of grant ($24.41).

As of December 31, 2017, Messrs. Leland and Lytal and Ms. Hildebrandt held 6,964, 6,964 and 6,760 phantom units, respectively, which will be settled in our common units.

Compensation Committee Interlocks and Insider Participation

As previously discussed, the Board is not required to maintain, and does not maintain, a compensation committee. Each of Messrs. Ashcroft, Gardner, McNally, Porges and Schlotterbeck, who are directors of our general partner, are also executive officers of EQT. However, all compensation decisions with respect to each of these executive officers are made by the EQT MDC Committee, and none of these individuals receives any compensation directly from us or our general partner for their service as a director.

Item 12. Security Ownership of Certain Beneficial Owners and Management

The following table sets forth the beneficial ownership of our common and subordinated units as of February 1, 2018 held by:


•	our general partner;


•	beneficial owners of 5% or more of our common units;


•	each director and named executive officer; and


•	all of our directors and executive officers as a group.

All of our subordinated units were converted to common units on a one-for-one basis on February 15, 2018.

The amounts and percentages of our common 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 common units shown as beneficially owned by them, subject to community property laws where applicable.



Name of Beneficial Owner ⁽¹⁾	Common Units Beneficially Owned ⁽²⁾	Percentage of Common Units Beneficially Owned ⁽³⁾		Subordinated Units Beneficially Owned	Percentage of Subordinated Units Beneficially Owned		Percentage of Common and Subordinated Units Beneficially Owned ⁽³⁾
EQT ⁽⁴⁾	3,623	*		28,753,623	100%		28.1	%
OppenheimerFunds, Inc. ⁽⁵⁾	8,037,144	10.9	%	—	—		7.9	%
Harvest Fund Advisors, LLC ⁽⁶⁾	7,105,148	9.7	%	—	—		6.9	%
Tortoise Capital Advisors, LLC ⁽⁷⁾	6,179,074	8.4	%	—	—		6.0	%
ALPS Advisors, Inc. ⁽⁸⁾	6,122,118	8.3	%	—	—		6.0	%
Salient Capital Advisors, LLC, LP ⁽⁹⁾	5,386,008	7.3	%	—	—		5.3	%
Goldman Sachs Asset Management ⁽¹⁰⁾	5,256,021	7.2	%	—	—		5.1	%
S.T. Schlotterbeck	—	*		—	—		*
R.J. McNally	—	*		—	—		*
J.J. Ashcroft III	—	*		—	—		*
L.B. Gardner	—	*		—	—		*
D.L. Porges	—	*		—	—		*
S.C. Hildebrandt	11,762	*		—	—		*
D.M. Leland	53,311	*		—	—		*
J.H. Lytal	17,566	*		—	—		*
R. F. Vagt	—	*		—	—		*
D.J. Rice IV	11,380	*		—	—		*
G.T. Lisenby	27,007	*		—	—		*
W.E. Jordan	17,611	*		—	—		*
R.R. Wingo	29,108	*		—	—		*
All directors and executive officers as a group (14 persons)	167,745	*		—	—	%	*


*	Less than one percent.


(1)	Unless otherwise indicated, the address for all beneficial owners in this table is c/o Rice Midstream Partners LP, 625 Liberty Avenue, Suite 1700, Pittsburgh, PA 15222.


(2)	This column does not include 6,694, 6,694, and 6,760 phantom units held by Messrs. Leland and Lytal and Ms. Hildebrandt, respectively, that were granted in connection with their respective service as directors and which will cliff vest at the end of the requisite service period in our common units.


(3)	Percentages of beneficial ownership are based on 73,549,485 common units and 28,753,623 subordinated units outstanding as of February 1, 2018. See Note 7 to the Consolidated Financial Statements for a discussion of the conversion of the subordinated units to common units.


(4)	As a result of the Mergers, EQT acquired beneficial ownership, indirectly through Rice Midstream GP Holdings LP, of 3,623 common units representing limited partner interests in us, 28,753,623 subordinated units representing limited partner interests in us and all of our incentive distribution rights.


(5)	Information based on an SEC Schedule 13G filed on February 6, 2018 reporting that OppenheimerFunds, Inc. has shared voting power and shared dispositive power over 8,037,144 common units. The address of the beneficial owner is 225 Liberty Street, New York, NY 10281.


(6)	Information based on an SEC Schedule 13G filed on October 26, 2017 reporting that Harvest Fund Advisors, LLC has sole voting power and sole dispositive power over 7,105,148 common units. The address of the beneficial owner is 100 W. Lancaster Avenue, Suite 200, Wayne, PA 19087.


(7)	Information based on an SEC Schedule 13G filed on February 13, 2018 reporting that Tortoise Capital Advisors, LLC has sole voting power and sole dispositive power over 1,156,485 common units and shared voting power and shared dispositive power over 5,022,589 common units. The address of the beneficial owner is 11550 Ash Street, Suite 300, Leawood, Kansas 66211.

(8)

Information based on SEC Schedule 13G filed on February 7, 2018 reporting that ALPS Advisors, Inc. has shared voting and shared dispositive power over 6,112,118 common units, of which 6,068,989 common units are attributable to Alerian MLP ETF, an investment company to which ALPS Advisors, Inc. furnishes investment advice. Alerian MLP ETF has shared voting and dispositive power with respect to the 6,068,989 common units. The address of the beneficial owner is 1290 Broadway, Suite 1100, Denver, CO 80203.


(9)	Unit information based on a SEC Schedule 13G filed on January 18, 2018 reporting that Salient Advisors, LLC has sole voting and dispositive power over 5,386,008 common units. The address of the beneficial owner is 4265 San Felipe, 8th Floor, Houston, Texas 77027.


(10)	Information based on an SEC Schedule 13G filed on February 7, 2018 reporting that Goldman Sachs Asset Management, LP has shared voting power and shared dispositive power over 5,256,021 common units. The address of the beneficial owner is 200 West Street, New York, NY 10282.

The following table sets forth the number of shares of common stock of EQT owned by each of the named executive officers and directors of our general partner and all directors and executive officers of our general partner as a group as of February 1, 2018. The percentage of total shares of EQT beneficially owned is based on 265,016,480 shares outstanding as of February 1, 2018.



Name	Exercisable Stock Options ⁽¹⁾	Number of EQT Shares Beneficially Owned ⁽²⁾	Percent of Class ⁽³⁾
S.T. Schlotterbeck ⁽⁴⁾	143,400	190,798	*
R.J. McNally	—	27,389	*
J.J. Ashcroft III	—	47,014	*
L.B. Gardner	33,300	47,575	*
D.L. Porges ⁽⁵⁾	299,700	502,108	*
S.C. Hildebrandt	—	—	*
D.M. Leland	—	—	*
J.H. Lytal	—	—	*
R.F. Vagt	—	18,669	*
D. J. Rice IV	—	223,419	*
G.T. Lisenby	—	61,719	*
W.E. Jordan	—	96,999	*
R.R. Wingo	—	72,471	*
All directors and executive officers as a group (14) persons	476,400	1,288,161	*


(1)	This column reflects the number of shares of EQT common stock that the executive officers and directors had a right to acquire within 60 days after February 1, 2018 through the exercise of stock options.

(2)

This column reflects shares held of record and shares owned through a bank, broker or other nominee, including, for EQT employees, shares owned through EQT’s 401(k) plan. For Messrs. Rice IV and Vagt, this column also reflects 380 deferred stock units, including accrued dividends thereon, awarded in connection with their service as non-employee directors of EQT that will be settled in EQT common stock, over which they have no voting or investment power prior to settlement.

(3)

This column reflects (i) the sum of the shares beneficially owned, the options exercisable within 60 days of February 1, 2018 and Messrs. Rice IV’s and Vagt’s deferred stock units that will be settled in EQT common stock, as a percentage of (ii) the sum of EQT’s outstanding shares at February 1, 2018, all options exercisable within 60 days of February 1, 2018 and Messrs. Rice IV’s and Vagt’s deferred stock units that will be settled in EQT common stock upon termination of their respective service on the EQT

Board of Directors.


(4)	Shares beneficially owned include 28,012 shares owned by Mr. Schlotterbeck's wife.


(5)	Shares beneficially owned include 50,000 shares that are held in a trust of which Mr. Porges is a co-trustee and in which he shares voting and investment power.

* Less than one percent.

Equity Compensation Plan Information

The following table provides information regarding securities authorized for issuance under our equity compensation plan as of December 31, 2017:



Plan Category	Number of Securities to be issued upon exercise of outstanding options, warrants and rights (a) ⁽¹⁾	Weighted average exercise price of outstanding options, warrants and rights (b) ⁽²⁾	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) ⁽³⁾
Equity compensation plans approved by security holders	—	—	—
Equity compensation plans not approved by security holders	20,688	N/A	7,168,344
Total	20,688	N/A	7,168,344


(1)	The amounts in column (a) of this table reflect only phantom units that are settled in our common units that have been granted under the RMP LTIP. No equity or equity-based awards have been granted by us other than phantom units under the RMP LTIP.


(2)	This column is not applicable because phantom units do not have an exercise price.

(3)

The figures in this column reflect the total number of common units remaining available for future issuance under the RMP LTIP as of December 31, 2017. Such figures take into account 7,500,000 million units provided under the RMP LTIP less phantom unit awards which have vested or remain outstanding at December 31, 2017. The RMP LTIP was adopted by our general partner in connection with but prior to the closing of our IPO and provides for the grant of a wide variety of cash and equity awards. For a summary of the material terms of the RMP LTIP, please refer to the section of our Registration Statement on Form S-1 initially filed with the SEC on December 8, 2014, entitled “Management-Long-Term Incentive Plan.”

Item 13. Certain Relationships and Related Transactions and Director Independence

As of February 15, 2018, EQT, indirectly through Rice Midstream GP Holdings LP, owned 28,757,246 common units representing an aggregate approximately 28% limited partner interest in us and all of the incentive distribution rights. EQT owns and controls (and appoints all the directors of) our general partner, which owns a non-economic general partner interest in us.

The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, are not the result of arm’s length negotiations. These terms are not necessarily at least as favorable to the parties to these transactions and agreements as the terms that could have been obtained from unaffiliated third parties.

Distributions and Payments to Our General Partner and Its Affiliates

The following summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the conversion, ongoing operation and any liquidation of us.

Formation Stage



The aggregate consideration received by our general partner and its affiliates, including Rice Energy, for the contribution of our initial assets	Ÿ 3,623 common units; Ÿ 28,753,623 subordinated units; Ÿ the non-economic general partner interest; Ÿ the incentive distribution rights; and Ÿ approximately $414.4 million of the net proceeds from our IPO, $195.3 million of which represents a reimbursement of capital expenditures incurred by Rice Energy on our behalf and $219.1 million of which represents a distribution to Rice Energy.

Operational Stage



Distributions of cash available for distribution to our general partner and its affiliates, including EQT	We will generally make cash distributions 100% to our unitholders, including affiliates of our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, EQT will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target distribution level. Assuming we have sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our outstanding common units for four quarters, our general partner and its affiliates (including EQT) would receive an annual distribution of approximately $21.6 million on their common units.

Payments to our general partner and its affiliates	EQT provides customary management and general administrative services to us. Our general partner reimburses EQT at cost for its direct expenses incurred on behalf of us and a proportionate amount of its indirect expenses incurred on behalf of us, including, but not limited to, compensation expenses. Our general partner does not receive a management fee or other compensation for its management of our partnership, but we reimburse our general partner and its affiliates for all direct and indirect expenses they incur and payments they make on our behalf, including payments made to EQT for customary management and general administrative services. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, 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. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us.

Withdrawal or removal of our general partner	If our general partner withdraws or is removed, its non-economic general partner interest and its incentive distribution rights and those of its affiliates 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.

Liquidation Stage



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

Agreements with Affiliates

Registration Rights Agreement

On December 22, 2014, in connection with the closing of our IPO, we entered into a registration rights agreement with Rice Energy pursuant to which we are required to register the sale of the (i) common units issued (or issuable) to Rice Energy pursuant to the contribution agreement and (ii) common units issued upon conversion of subordinated units pursuant to the terms of our partnership agreement (together, the Registrable Securities) it holds. As a result of the Mergers, the rights of Rice Energy under the registration rights agreement vested in EQT RE, LLC (LLC Sub), an indirect wholly owned subsidiary of EQT of which our general partner is an indirect wholly owned subsidiary. Under the registration rights agreement, LLC Sub

has the right to request that we register the sale of Registrable Securities held by it, certain of its affiliates and any permitted transferee, and LLC Sub has the right to require us to make available shelf registration statements permitting sales of Registrable Securities into the market from time to time over an extended period, subject to certain limitations. Pursuant to the registration rights agreement and our partnership agreement, we were required to undertake a future public or private offering and use the proceeds (net of underwriting or placement agency discounts, fees and commissions, as applicable) to redeem an equal number of common units from them. In addition, the registration rights agreement gives LLC Sub “piggyback” registration rights under certain circumstances. The registration rights agreement also included provisions dealing with indemnification and contribution and allocation of expenses. All of the Registrable Securities held by LLC Sub and certain of its affiliates and any permitted transferee are entitled to these registration rights.

Omnibus Agreement

On December 22, 2014, in connection with the closing of our IPO, we entered into an omnibus agreement with our general partner, Rice Midstream Holdings LLC and Rice Energy. On November 13, 2017, in connection with the Mergers, EQT, us, our general partner and certain other affiliates of EQT entered into an amended and restated omnibus agreement, pursuant to which:


•	EQT joined the amended and restated omnibus agreement as a party and assumed certain rights and obligations of LLC Sub (as successor-in-interest to Rice Energy) as further discussed below;


•	EQT granted us a right of first offer, subject to certain exceptions, on any future divestiture of EQT’s (or its affiliates’) interests in its gas gathering system in the Utica Shale in Belmont County, Ohio, which is a continuation of the right of first offer granted by Rice Energy under the omnibus agreement entered into in connection with our IPO;

•

We are obligated to reimburse EQT or its designees for all expenses incurred by EQT or its affiliates (or payments made on our behalf) in conjunction with its provision of general and administrative services to us, including but not limited to, our publicly traded partnership expenses and an allocated portion of the compensation expense of the executive officers and other employees of EQT and its affiliates who perform general and administrative services for us or on our behalf; and


•	LLC Sub (as successor-in-interest to Rice Energy) has provided us with a license to use certain Rice Energy-related names and trademarks in connection with our operations.

We have agreed to indemnify LLC Sub (as successor-in-interest to Rice Energy) and EQT against all losses, including environmental liabilities, related to the operation of our assets after the closing of our IPO, to the extent LLC Sub is not required to indemnify us. There is no limit on the amount for which we will indemnify LLC Sub and EQT under the amended and restated omnibus agreement. As a result, we may incur such expenses in the future, which may be substantial.

These indemnification agreements are continuations of the indemnification agreements made under the omnibus agreement entered into in connection with our IPO.

The initial term of the amended and restated omnibus agreement expires on December 22, 2024 and will thereafter automatically extend from year-to-year unless terminated by us or our general partner. We or EQT may also terminate the amended and restated omnibus agreement in the event EQT ceases to control our general partner or our general partner is removed as general partner of us. The amended and restated omnibus agreement may only be assigned by a party with the other parties’ consent.

Secondment Agreement

On November 13, 2017, in connection with the Mergers, we, EQT, and certain affiliates of EQT entered into an amended and restated employee secondment agreement, pursuant to which:


•	EQT joined the amended and restated employee secondment agreement as a party and assumed the rights and obligations of LLC Sub (as successor-in-interest to Rice Energy) thereunder; and


•	specified employees of EQT (or certain of its affiliates) will be seconded to us to provide operating and other services with respect to our business under the direction, supervision and control of us or our general partner.

We will reimburse EQT (or its affiliates, as appropriate) for the services provided by the seconded employees pursuant to the amended and restated employee secondment agreement.

Reimbursement of Expenses

100

The table below sets forth the amounts of expenses described above for which we were obligated to reimburse EQT or its affiliates pursuant to the amended and restated omnibus agreement and the amended and restated employee secondment agreement for the years ended December 31, 2017, 2016 and 2015.



	Years Ended December 31,
(in thousands)	2017		2016		2015
DESCRIPTION OF EXPENSES
Reimbursement under omnibus agreement	$	19,366	$	16,597	$	11,863
Reimbursement under secondment agreement	$	2,860	$	—	$	—

The expenses for which we reimburse EQT and its affiliates may not necessarily reflect the actual expenses that we would incur on a stand-alone basis and we are unable to estimate what those expenses would be.

Other Contractual Relationships with Rice Energy and EQT

Vantage Midstream Asset Acquisition

On September 26, 2016, we entered into a Purchase and Sale Agreement with Rice Energy, pursuant to which we agreed to acquire from Rice Energy all of the outstanding membership interests of Vantage Energy Appalachia LLC, Vantage Energy II Alpha, LLC, Vantage Energy II Access, LLC and Vista Gathering, LLC (collectively, such entities, the Vantage Midstream Entities and such transactions, the Vantage Midstream Asset Acquisition). The closing of the Vantage Midstream Asset Acquisition occurred on October 19, 2016. The aggregate consideration paid by us to Rice Energy in connection with the Vantage Midstream Asset Acquisition was $600 million. The Vantage Midstream Entities owned midstream assets including 30 miles of dry gas gathering and compression at the time of the transaction.

Rice Water Services Acquisition

On November 4, 2015, we entered into a Purchase and Sale Agreement with Rice Energy, pursuant to which we acquired from Rice Energy all of the outstanding limited liability company interests of Rice Water Services (PA) LLC and Rice Water Services (OH) LLC (the Rice Water Services Acquisition). The acquired business included Rice Energy’s Pennsylvania and Ohio fresh water distribution systems and related facilities that provided access to 43.4 MMgal/d of fresh water from the Monongahela River, the Ohio River and other regional water sources in Pennsylvania and Ohio as of December 31, 2017 (the Water Assets). In connection with the Rice Water Services Acquisition, Rice Energy also granted us, until December 31, 2025, (i) the exclusive right to develop water treatment facilities in the areas of dedication defined in the Water Services Agreements (as further discussed below) and (ii) an option to purchase any water treatment facilities acquired by certain subsidiaries of EQT in such areas at the acquisition cost (collectively, the Option). The closing of the Rice Water Services Acquisition occurred on November 4, 2015. The aggregate consideration paid by RMP to Rice Energy in connection with the acquisition of the PA Water and OH Water and the receipt of the Option was $200 million in cash, which was funded with borrowings under our revolving credit facility.

Gas Gathering and Compression Agreements

EQT, inclusive of Rice Energy for periods prior to the Mergers, accounted for substantially all of our gathering and compression revenues for the year ended December 31, 2017.

IPO Gas Gathering Agreement

On December 22, 2014, we entered into a fixed price per unit gathering and compression agreement with Rice Energy (now EQT) that expires in December 2029 under which we have agreed to gather natural gas on certain of our Washington and Greene Counties, Pennsylvania gathering systems and provide compression services. Under the agreement, we charge EQT a gathering fee of $0.30 per Dth and a compression fee of $0.07 per Dth per stage of compression, each subject to annual adjustment for inflation based on the Consumer Price Index. This agreement covers approximately 209,000 gross acres of EQT’s acreage position in the dry gas core of the Marcellus Shale in southwestern Pennsylvania as of December 31, 2017 and, subject to certain exceptions and limitations pursuant to the gathering and compression agreement, any future acreage certain affiliates of EQT acquire within these counties.

Pursuant to the gas gathering and compression agreement, EQT will from time to time provide us with notice of the date on which it expects to require gas production to be delivered from a particular well pad. Subject to the provisions described in the following paragraph, we will be obligated to build out our gathering systems to such well pad and to install facilities to connect all wells planned for such well pad as soon as reasonably practicable, but in any event within one year of

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receipt of such notice, subject to extension for force majeure, including inability to obtain or delay in obtaining permits and rights of way.

We will be obligated to connect all of EQT’s wells that produce gas from the area dedicated to us under the gas gathering and compression agreement that (i) were completed as of the closing date of our IPO, (ii) were included in Rice Energy’s initial development plan for drilling activity for the period from the closing date of our IPO through December 31, 2017 or (iii) are within five miles of our gas gathering system on the date EQT provides us with notice that a new well pad is expected to require gathering services. For wells other than those described in the preceding sentence, we and EQT will negotiate in good faith an appropriate gathering fee. If we cannot reach agreement with EQT on a gathering fee for any such additional well, EQT will have the option to have us connect such well to our gathering systems for a gathering fee of $0.30 per Dth and bear the incremental cost of constructing the connection to such well in excess of the cost we would have incurred to connect a well located on the five-mile perimeter, or EQT will cause such well to be released from our dedication under the gas gathering and compression agreement.

Cracker Jack Gas Gathering Agreement

On December 18, 2015, we entered into a fixed price per unit gathering and compression agreement with EQT, pursuant to which we have agreed to gather natural gas on our Washington County, Pennsylvania gathering system and provide compression services to EQT. The current term of this agreement expires in January 2021 with a 10-year extension term and renews on an annual basis after the expansion term. Under the agreement, we receive fixed gathering and compression fees per Dth, each subject to annual adjustment for inflation based on the Consumer Price Index. This agreement covers the Cracker Jack Area of Mutual Interest, which consists of approximately 29,000 gross acres of EQT’s acreage position in Washington County (the CJ AMI) as of December 31, 2017. Upon notice from EQT, we will be obligated to connect additional EQT wells within the CJ AMI. Following receipt of all necessary permits and rights of way relating to such additional connections, we will have three weeks for completion of each mile of pipeline required for such connection, with the exception of any pipeline to be located less than one mile from our existing gathering system, for which the connection must be completed within eight weeks of receiving all necessary permits and rights of way.

Cash Dollar Gas Gathering Agreement

On October 21, 2015, we entered into a 15 year, fixed price per unit gathering and compression agreement with EQT under which we have agreed to gather natural gas on our Washington County, Pennsylvania gathering system and provide compression services to EQT. Under the agreement, we receive fixed gathering and compression fees per Dth, each subject to annual adjustment for inflation based on the Consumer Price Index. This agreement covers approximately 2,200 gross acres of EQT’s acreage position in Washington County as of December 31, 2017.

Appalachia North Gathering System Gas Gathering Agreement

Effective as of December 16, 2016, in connection with an acquisition by EQT, EQT assumed the obligations under the Appalachia North Gathering System Gas Gathering Agreement, to which we are a party. Under this agreement, we have agreed to gather natural gas on our Washington County, Pennsylvania gathering system and provide compression services to EQT. Under the agreement, we receive fixed gathering and compression fees per Dth, each subject to annual adjustment for inflation based on the Consumer Price Index. The initial term of this agreement is until December 31, 2023 and it covers approximately 4,000 gross acres of EQT’s acreage position in Washington County as of December 31, 2017.

Windridge Gas Gathering Agreement

Effective as of October 19, 2016, in connection with the Vantage Midstream Asset Acquisition, we acquired Vantage Energy II Access LLC, which is party to a gas gathering agreement with an affiliate of EQT pursuant to which we have agreed to gather natural gas on our Windridge gathering system and provide compression and dehydration services to EQT. The initial term of this agreement expires in December 2023, with monthly renewal terms thereafter. Under the agreement, we receive fixed gathering, compression and dehydration fees per Dth, each subject to an annual adjustment for inflation based upon the Consumer Price Index. Under this agreement, EQT dedicates the first 20,000 Dth per day of gas in Greene County, Pennsylvania to the Windridge gathering system, and may also deliver gas from the Utica formation or other locations outside the dedicated acreage, which will count towards EQT’s dedication. Upon notice from EQT, we will be obligated to connect additional receipt and delivery points on the Windridge gathering system at EQT’s sole cost.

Additionally, prior to the Vantage Midstream Asset Acquisition, our subsidiary, Vantage Energy II Access LLC, was party to a letter agreement with an affiliate of EQT, among other parties, pursuant to which we agreed to facilitate the crossflow of EQT’s gas into our Windridge gathering system from our Rogersville gathering system for an additional 25% of the gathering fee and an additional 100% of the compression fee applicable to services provided to EQT on our Windridge

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gathering system. These obligations continued with Vantage Energy II Access LLC following the Vantage Midstream Asset Acquisition.

Whipkey Gas Gathering Agreement

On November 25, 2015, our subsidiary, Rice Poseidon Midstream LLC, entered into a fixed price per unit gas gathering agreement with a subsidiary of EQT pursuant to which we agreed to gather and compress natural gas on our Whipkey gathering system and to connect our gathering system with the ASR gathering system. The primary term of this agreement expires in November 2025, with yearly evergreen renewal terms thereafter. We receive fixed gathering and compression fees per Dth. Additionally, we receive an interconnect fee on a monthly basis per Dth received at each applicable receipt point. All fees are subject to an annual adjustment based on the Consumer Price Index. This agreement covers approximately 2,200 gross acres of EQT’s gross acreage position in Greene County, Pennsylvania. Under this agreement, EQT dedicates all gas from the subject acreage to our Whipkey gathering system.

Water Services Agreements

EQT, inclusive of Rice Energy for periods prior to the Mergers, accounted for approximately 96% , of our water services revenues for the year ended December 31, 2017.

Rice Water Services Agreements

On November 4, 2015, we entered into water services agreements with Rice Energy, whereby we have agreed to provide certain fluid handling services, including the exclusive right to provide fresh water for well completions operations in the Marcellus and Utica Shales and to collect and recycle or dispose of flowback and produced water within areas of dedication in defined service areas in Pennsylvania and Ohio. In consideration for the acquisition of the Water Assets, we paid Rice Energy $200.0 million in cash. The initial term of the Water Services Agreements expires in December 2029 and continues from month to month thereafter. Under the agreements, we will receive (i) a variable fee, based on volumes of water supplied, for freshwater deliveries by pipeline directly to the well site, subject to annual CPI adjustments, and (ii) a produced water hauling fee of actual out-of-pocket cost incurred by us, plus a 2% margin.

Water System Expansion Agreement

Effective as of October 19, 2016, in connection with the Vantage Midstream Asset Acquisition, we acquired Vista Gathering LLC, which is party to a water system expansion and supply agreement with an affiliate of EQT and Southwestern Pennsylvania Water Authority (SPWA) pursuant to which we and EQT have agreed to jointly fund and assist SPWA in the construction and expansion of its water supply system serving parts of Greene, Fayette and Washington Counties in Pennsylvania. To date, we and EQT have executed authorizations for expenditure totaling approximately $29.5 million, and have funded approximately $9.7 million during the year ended 2017. In exchange for our and EQT’s agreement to fund this construction and expansion, SPWA granted to us and EQT preferred rights to water volumes supplied through the system for use in our and EQT’s oil and gas operations. Additionally, we and EQT are entitled to receive a surcharge assessed by SPWA against all oil and gas customers to whom water is supplied through the system in an amount equal to $3.50 per 1,000 gallons of water sold. All facilities and improvements constructed pursuant to the agreement are the property of SPWA.

EQT Water Services Agreement

On June 13, 2017, we entered into a Second Amended and Restated Water Services Agreement with EQT, whereby we have agreed to provide certain freshwater services to EQT for various delivery points in Washington and Greene Counties, Pennsylvania. The term of the agreement expires on October 15, 2020. Under the agreement, we receive fees per gallon based upon the relevant delivery point.

Pipeline, Construction, Ownership and Operating Agreement

A subsidiary of EQT is party to a Pipeline, Construction, Ownership and Operating Agreement, or the Whipkey Agreement, pursuant to which it owns a 60% working interest in a joint venture that owns a natural gas gathering pipeline in Greene County, Pennsylvania. The gathering pipeline owned by the joint venture is connected to seven producing wells operated by EQT. The Whipkey Agreement was contributed to us in connection with the closing of our IPO. We recognized approximately $2.1 million, $0.6 million and $0.3 million of revenue, respectively, during the years ended December 31, 2017, 2016 and 2015, respectively, pursuant to the Whipkey Agreement.

The table below sets forth the revenues recognized by RMP with respect to the gathering and compression and water services agreements described above with EQT (inclusive of Rice Energy) for the years ended December 31, 2017, 2016 and

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2015.



(in thousands)	Years Ended December 31,
Description of Revenue	2017		2016		2015
Gathering and compression	$	198,106	$	132,099	$	77,211
Water services	$	96,587	$	69,524	$	37,248

Procedures for Review, Approval and Ratification of Transactions with Related Persons

On November 13, 2017, our Board of Directors adopted a new related person transaction approval policy, which includes procedures for the identification, review and approval of related person transactions. Pursuant to the policy, the management of our general partner is charged with primary responsibility for determining whether, based on the facts and circumstances, a proposed transaction is a related person transaction.

For purposes of the policy, a “Related Person” is any director or executive officer of our general partner, any nominee for director, any unitholder known to us to be the beneficial owner of more than 5% of any class of our voting securities, and any immediate family member of any such person. A “Related Person Transaction” is generally a transaction in which we are, or our general partner or any of its subsidiaries is, a participant, where the amount involved exceeds $120,000, and a Related Person has a direct or indirect material interest. Transactions resolved under the conflicts provision of our partnership agreement are not required to be reviewed or approved under the policy. Please read “Conflicts of Interest” below.

To assist management in making this determination, the policy sets forth certain categories of transactions that are deemed to be pre-approved by the Board under the policy. The transactions which are automatically pre-approved include (i) transactions involving employment of our general partner’s executive officers, as long as the executive officer is not an immediate family member of another of our general partner’s executive officers or directors and the compensation paid to such executive officer was approved by the Board; (ii) transactions involving compensation and benefits paid to our general partner’s directors for service as a director; (iii) transactions on competitive business terms with another company in which a director or immediate family member of the director’s only relationship is as an employee or executive officer, a director, or beneficial owner of less than 10% of that company’s shares, provided that the amount involved does not exceed the greater of $1,000,000 or 2% of the other company’s consolidated gross revenues; (iv) transactions where the interest of the Related Person arises solely from the ownership of a class of our equity securities, and all holders of that class of equity securities receive the same benefit on a pro rata basis; (v) transactions where the rates or charges involved are determined by competitive bids; (vi) transactions involving the rendering of services as a common or contract carrier or public utility at rates or charges fixed in conformity with law or governmental regulation; (vii) transactions involving services as a bank depositary of funds, transfer agent, registrar, trustee under a trust indenture or similar services; and (viii) any charitable contribution, grant or endowment by us or any affiliated charitable foundation to a charitable or non-profit organization, foundation or university in which a Related Person's only relationship is as an employee or a director or trustee, provided the aggregate amount involved does not exceed the greater of $1,000,000 or 2% of the recipient’s consolidated gross revenues.

If, after applying these categorical standards and weighing all of the facts and circumstances, management determines that a proposed transaction is a Related Person Transaction, management must present the proposed transaction to the Board for review or, if impracticable under the circumstances, to the Chairman of the Board. The Board must then either approve or reject the transaction in accordance with the terms of the policy taking into account all facts and circumstances, including (i) the benefits to us of the transaction; (ii) the terms of the transaction; (iii) the terms available to unaffiliated third parties and employees generally; (iv) the extent of the affected director or executive officer’s interest in the transaction; and (v) the potential for the transaction to affect the individual's independence or judgment. The Board may, but is not required to, seek the approval of the Conflicts Committee for the resolution of any related person transaction.

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, EQM, EQGP, the EQM General Partner and the EQGP General Partner, on the one hand, and us and our limited partners, on the other hand. The directors and officers of our general partner have duties to manage our general partner in a manner beneficial to its owner, EQT. At the same time, our general partner has a duty to manage us in a manner beneficial to us and our limited partners. The Delaware Revised Uniform Limited Partnership 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. Pursuant to these provisions, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of the general partner and the methods of resolving conflicts of interest. Our partnership agreement also

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specifically defines the remedies available to limited partners for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.

All of our general partner’s executive officers and five of its directors are also officers and/or directors of the EQM General Partner, which has duties to manage the business of EQM in a manner beneficial to EQM and its unitholders. Additionally, three of our general partner’s executive officers and four of its directors are also officers and/or directors of the EQGP General Partner, which has duties to manage the business of EQGP in a manner beneficial to EQGP and its unitholders. Finally, all of our executive officers and six of our directors are also officers and/or directors of EQT. Consequently, these directors and officers may encounter situations in which their obligations to EQM, the EQM General Partner, EQGP, the EQGP General Partner or EQT, as applicable, on the one hand, and us, on the other hand, are in conflict.

Whenever a conflict arises between our general partner or its affiliates, including EQT, EQM, EQGP, the EQM General Partner and the EQGP General Partner on the one hand, and us, any of our subsidiaries, any partner or any other person with an interest in us or who is party to the partnership agreement, on the other, our general partner may in its discretion seek the approval of any resolution, course of action with respect to, or causing, such conflict, or transaction from the Conflicts Committee of the Board or the holders of our common units (other than our general partner and its affiliates). There is no requirement that our general partner seek the approval of the Conflicts Committee for the resolution of any conflict. Our general partner will decide whether to refer the matter to the Conflicts Committee on a case-by-case basis. An independent third party is not required to evaluate the fairness of the resolution, course of action or transaction.

Our general partner will not be in breach of its obligations under the partnership agreement, the organizational documents of our subsidiaries, any agreements contemplated thereby or its fiduciary or other duties to us or our limited partners if the resolution of the conflict is:


•	approved by the Conflicts Committee of our general partner, although our general partner is under no obligation to seek such approval; or


•	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.

Any resolution, course of action or transaction so approved will be conclusively deemed to be approved by us, all partners and any other person with an interest in us or who is bound by the partnership agreement.

Our partnership agreement permits our general partner to consult with legal counsel, investment bankers and other advisors in making decisions, though the extent to which our general partner will seek such advice will depend on the facts and circumstances of the transaction being considered. If our general partner reasonably believes that advice or an opinion provided by such advisors is within such person's professional or expert competence, then any act taken in reliance upon such advice or opinion will conclusively be deemed to have been done or omitted in good faith and in accordance with such advice or opinion.

Item 14. Principal Accountant Fees and Services

Ernst & Young LLP (E&Y) served as our independent auditor for the fiscal years ended December 31, 2017 and 2016 . The following table presents fees billed to RMP by E&Y during 2017 and 2016.



(in thousands)	2017		2016
Audit Fees ⁽¹⁾	$	607.0	$	740.0
Audit-Related Fees	—		—
Tax Fees	—		—
All Other Fees	—		—
Total	$	607.0	$	740.0


(1)	For fiscal year 2017 and 2016, includes E&Y fees for professional services provided in connection with (a) audit of our financial statements and internal control over financial reporting, (b) review of our quarterly consolidated financial statements and (c) review of our filings with the SEC, including review of registration statements, comfort letters and consents.


(2)	$213,933 of the total audit fees for 2017 was incurred following the closing of the Mergers.

The Audit Committee of Midstream Management has adopted a policy regarding the services of its independent auditors under which RMP’s independent accounting firm is not allowed to perform any service that may have the effect of jeopardizing the independent public accountant’s independence. Without limiting the foregoing, the independent accounting firm shall not be retained to perform the following:

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•	Bookkeeping or other services related to the accounting records or financial statements


•	Financial information systems design and implementation


•	Appraisal or valuation services, fairness opinions or contribution-in-kind reports


•	Actuarial services


•	Internal audit outsourcing services


•	Management functions


•	Human resources functions


•	Broker-dealer, investment adviser or investment banking services


•	Legal services


•	Expert services unrelated to the audit


•	Prohibited tax services

All audit and permitted non-audit services must be pre-approved by the Audit Committee. The Audit Committee has delegated specific pre-approval authority with respect to audit and permitted non-audit services to the Chairman of the Audit Committee but only where pre-approval is required to be acted upon prior to the next Audit Committee meeting and where the aggregate audit and permitted non-audit services fees are not more than $75,000. The Audit Committee encourages management to seek pre-approval from the Audit Committee at its regularly scheduled meetings. In 2017, 100% of the professional fees reported as audit-related fees were pre-approved pursuant to the above policy.

The Audit Committee of Midstream Management has approved the appointment of Ernst & Young LLP as RMP’s independent auditor to conduct the audit of RMP’s consolidated financial statements for the year ended December 31, 2018.

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PART IV

Item 15. Exhibits and Financial Statement Schedules


a.	The following documents are filed as a part of this Annual Report on Form 10-K or incorporated herein by reference:


(1)	Financial Statements:

See Item 8. Financial Statements and Supplementary Data.


(2)	Financial Statement Schedules:

None.


(3)	Exhibits:

The exhibits referenced below are filed (or, as applicable, furnished) as part of this Annual Report on Form 10-K.

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Exhibits are incorporated by reference or are filed with this report as indicated below (numbered in accordance with Item 601 of Regulation S-K).



Exhibit No.	Description
2.1***	Purchase and Sale Agreement, dated as of November 4, 2015, by and between Rice Energy Inc. and Rice Midstream Partners LP (incorporated by reference to Exhibit 2.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36789) filed with the Commission on November 5, 2015).
2.2***	Purchase and Sale Agreement, dated as of September 26, 2016, by and between Rice Energy Inc. and Rice Midstream Partners LP (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36789) filed with the Commission on September 30, 2016).
3.1	Amended and Restated Certificate of Limited Partnership of Rice Midstream Partners LP, dated as of December 8, 2017 (incorporated by reference to Exhibit 3.2 of the Partnership’s Current Report on Form 8-K (File No. 001-36789) filed with the Commission on December 8, 2017).
3.2	Amended and Restated Agreement of Limited Partnership of Rice Midstream Partners LP, dated as of December 22, 2014 (incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36789) filed with the Commission on December 22, 2014).
3.3	Amendment No. 1 to the Amended and Restated Agreement of Limited Partnership of Rice Midstream Partners LP, dated as of December 7, 2017 (incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36789) filed with the Commission on December 8, 2017).
3.4	Certificate of Formation of Rice Midstream Management LLC (incorporated by reference to Exhibit 3.3 of the Partnership’s Confidential Draft Submission No. 1 Registration Statement on Form S-1 (File No. 377-00804) filed with the Commission on October 3, 2014).
3.5	Amended and Restated Limited Liability Company Agreement of Rice Midstream Management LLC, dated as of December 22, 2014 (incorporated by reference to Exhibit 3.2 of the Partnership’s Current Report on Form 8-K (File No. 001-36789) filed with the Commission on December 22, 2014).
4.1	Registration Rights Agreement, dated as of December 22, 2014, by and between Rice Midstream Holdings LLC and Rice Midstream Partners LP (incorporated by reference to Exhibit 10.5 of the Partnership’s Current Report on Form 8-K (File No. 001-36789) filed with the Commission on December 22, 2014).
4.2	Registration Rights Agreement, dated as of November 10, 2015, by and among Rice Midstream Partners LP and the Purchasers named on Schedule A thereto (incorporated by reference to Exhibit 4.1 of the Partnership’s Registration Statement on Form S-1 (File No. 333-207977) filed with the Commission on November 13, 2015).
4.3	Registration Rights Agreement, dated as of October 7, 2016, by and among Rice Midstream Partners LP and the Purchasers named on Schedule A thereto (incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36789) filed with the Commission on October 11, 2016).
10.1	Amended and Restated Omnibus Agreement, dated as of November 13, 2017, by and among EQT Corporation, EQT RE, LLC, Rice Midstream Holdings LLC, Rice Midstream Partners LP, Rice Midstream Management LLC and Rice Poseidon Midstream LLC (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36789) filed with the Commission on November 14, 2017).
10.2	Gas Gathering and Compression Agreement, dated as of December 22, 2014, by and between Rice Drilling B LLC, Rice Midstream Partners LP and Alpha Shale Resources LP (incorporated by reference to Exhibit 10.3 of the Partnership’s Current Report on Form 8-K (File No. 001-36789) filed with the Commission on December 22, 2014).
10.3	Credit Agreement, dated as of December 22, 2014, by and among Rice Midstream Partners LP, as parent guarantor, Rice Midstream OpCo LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent, certain lenders party thereto and the other parties thereto (incorporated by reference to Exhibit 10.6 of the Partnership’s Current Report on Form 8-K (File No. 001-36789) filed with the Commission on December 22, 2014).
10.4	First Amendment to Credit Agreement, dated as of January 13, 2016, by and among Rice Midstream Partners LP, as parent guarantor, Rice Midstream OpCo LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent, and the lenders and other parties thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 801-36789) filed with the Commission on January 15, 2016).
10.5	Second Amendment to Credit Agreement, dated as of October 19, 2016, by and among Rice Midstream Partners LP, Rice Midstream OpCo LLC, the guarantors party thereto, Wells Fargo Bank, N.A., as administrative agent and the lenders party thereto, Barclays Bank PLC as syndication agent, Wells Fargo Securities, LLC and Barclays Bank PLC as joint lead arrangers and joint bookrunners (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36789) filed with the Commission on October 25, 2016).
10.6	Amended and Restated Employee Secondment Agreement, dated as of November 13, 2017, by and among EQT Corporation, EQT RE, LLC and Rice Midstream Partners LP (incorporated by reference to Exhibit 10.2 of the Partnership’s Current Report on Form 8-K (File No. 001-36789) filed with the Commission on November 14, 2017).
10.7†	Rice Midstream Partners LP 2014 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.3 of the Partnership’s Registration Statement on Form S-8 (File No. 333-201169) filed with the Commission on December 19, 2014).

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10.8†	Form of Phantom Unit Agreement- Equity Settled under the Rice Midstream Partners LP 2014 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.4 of the Partnership’s Registration Statement on Form S-8 (File No. 333-201169) filed with the Commission on December 19, 2014).
10.9†	Form of Phantom Unit Agreement- Cash Settled under the Rice Midstream Partners LP 2014 Long- Term Incentive Plan (incorporated by reference to Exhibit 4.5 of the Partnership’s Registration Statement on Form S-8 (File No. 333-201169) filed with the Commission on December 19, 2014).
10.10	Equity Distribution Agreement, dated as of May 9, 2016, by and among Rice Midstream Partners LP, Rice Midstream Management LLC, and the Managers named therein (incorporated by reference to Exhibit 1.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36789) filed with the Commission on May 9, 2016).
10.11	Amended and Restated Water Services Agreement, dated as of November 4, 2015, by and between Rice Drilling B LLC and Rice Water Services (PA) LLC (incorporated by reference to Exhibit 10.2 of the Partnership’s Current Report on Form 8-K (File No. 001-36789) filed with the Commission on November 5, 2015).
10.12	Amended and Restated Water Services Agreement, dated as of November 4, 2015, by and between Rice Drilling D LLC and Rice Water Services (OH) LLC (incorporated by reference to Exhibit 10.3 of the Partnership’s Current Report on Form 8-K (File No. 001-36789) filed with the Commission on November 5, 2015).
10.13†	Form of Director and/or Officer Indemnification Agreement (incorporated by reference to Exhibit 10.3 of the Partnership’s Current Report on Form 8-K (File No. 001-36789) filed with the Commission on November 14, 2017).
10.14*	Sixth Amended and Restated Cracker Jack Gas Gathering Agreement, by and among Rice Poseidon Midstream LLC, EQT Energy, LLC, and EQT Production Company, dated as of February 28, 2017. Specific items in this exhibit have been redacted, as marked by three asterisks [***], because confidential treatment for those items has been requested from the Commission. The redacted material has been separately filed with the Commission.
21.1*	List of Subsidiaries of Rice Midstream Partners LP.
23.1*	Consent of Independent Registered Public Accounting Firm.
31.1*	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, Rule 13a-14(a)/15d-14(a), by Chief Executive Officer.
31.2*	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, Rule 13a-14(a)/15d-14(a), by Chief Financial Officer.
32**	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Principal Executive Officer and Principal Financial Officer.
99*	Non-GAAP Financial Information
101*	Interactive Data File.

*	Filed herewith.
**	Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this Annual Report on Form 10-K and not “filed” as part of such report for purposes of Section 18 of the Securities Exchange Act, as amended, or otherwise subject to the liability of Section 18 of the Securities Exchange Act, as amended, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Exchange Act of 1933, as amended, except to the extent that the registrant specifically incorporates it by reference.
***	The schedules to this agreement have been omitted from this filing pursuant to Item 601(b)(2) of Regulation S-K. The Partnership will furnish copies of such schedules to the Securities and Exchange Commission upon request.
†	Management contract or compensatory plan or agreement.

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Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



	RICE MIDSTREAM PARTNERS LP

By:	Rice Midstream Management LLC, its General Partner
By:	/s/ STEVEN T. SCHLOTTERBECK
	Steven T. Schlotterbeck
	President and Chief Executive Officer
	February 15, 2018

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



Signature	Title (Position with Rice Midstream Management LLC)	Date

/s/ STEVEN T. SCHLOTTERBECK	President, Chief Executive Officer, and Director	February 15, 2018
Steven T. Schlotterbeck	(Principal Executive Officer)

/s/ ROBERT J. MCNALLY	Senior Vice President, Chief Financial Officer, and Director	February 15, 2018
Robert J. McNally	(Principal Financial Officer)

/s/ JIMMI SUE SMITH	Chief Accounting Officer	February 15, 2018
Jimmi Sue Smith	(Principal Accounting Officer)

/s/ JEREMIAH J. ASHCROFT III	Director	February 15, 2018
Jeremiah J. Ashcroft III

/s/ LEWIS B. GARDNER	Director	February 15, 2018
Lewis B. Gardner

/s/ STEPHANIE C. HILDEBRANDT	Director	February 15, 2018
Stephanie C. Hildebrandt

/s/ D. MARK LELAND	Director	February 15, 2018
D. Mark Leland

/s/ JAMES H. LYTAL	Director	February 15, 2018
James H. Lytal

/s/ DAVID L. PORGES	Chairman	February 15, 2018
David L. Porges

/s/ ROBERT F. VAGT	Director	February 15, 2018
Robert F. Vagt

110

GLOSSARY OF TERMS

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in our industry:

Appalachian Basin: The area of the United States composed of those portions of West Virginia, Pennsylvania, Ohio, Maryland, Kentucky and Virginia that lie in the Appalachian Mountains.

Bcfe: One billion cubic feet of natural gas equivalent, determined by using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate of natural gas liquids.

Bgal: One billion gallons.

capacity : Pipeline capacity available to transport natural gas based on system facilities and design conditions.

condensate : Similar to crude oil and produced in association with natural gas gathering and processing.

DOT : U.S. Department of Transportation.

EPA : U.S. Environmental Protection Agency.

FERC : Federal Energy Regulatory Commission.

field : The general area encompassed by one or more oil or gas reservoirs or pools that are located on a single geologic feature, that are otherwise closely related to the same geologic feature (either structural or stratigraphic).

GAAP : Accounting principles generally accepted in the United States.

gas: All references to “gas” refer to natural gas.

horizontal wells: Wells that are drilled horizontal or near horizontal to increase the length of the well bore penetrating the target formation.

hydrocarbon : An organic compound containing only carbon and hydrogen.

IPO : Initial public offering.

IRS : U.S. Internal Revenue Service.

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

Longwall coal mining : A productive underground mining method in the United States. A shearer with two rotating cutting drums trams across the longwall face, cutting the coal and transferring it to an armored chain conveyor. Hydraulic supports hold the roof as the longwall system advances through the coal.

MDth: One thousand dekatherms.

MDth/d: One thousand dekatherms per day.

MMDth/d : One million dekatherms per day.

MMgal : One million gallons.

MMgal/d : One million gallons per day.

natural gas : Hydrocarbon gas found in the earth, composed of methane, ethane, butane, propane and other gases.

NGLs : Natural gas liquids, which consist primarily of ethane, propane, isobutane, normal butane and natural gasoline.

NYMEX : New York Mercantile Exchange.

oil : Crude oil and condensate.

play : A proven geological formation that contains commercial amounts of hydrocarbons.

reservoir: A porous and permeable underground formation containing an individual and separate natural accumulation of

111

producible hydrocarbons (crude oil and/or natural gas) which is confined by impermeable rock of water barriers and is

characterized by a single natural pressure system.

SEC : U.S. Securities and Exchange Commission.

Tcfe: T rillion cubic feet of natural gas equivalents, with one barrel of NGLs and crude oil being equivalent to 6,000 cubic

feet of natural gas.

throughput : The volume of product passing through a pipeline, plant, terminal or other facility.

112

EXHIBIT 10.14

Portions of this Exhibit have been redacted pursuant to a request for confidential treatment under Rule 24b-2 of the General Rules and Regulations under the Securities Exchange Act. Omitted information marked “[***]” in this Exhibit has been filed with the Securities and Exchange Commission together with such request for confidential treatment.

SIXTH AMENDED AND RESTATED CRACKER
JACK GAS GATHERING AGREEMENT

By and Among

RICE POSEIDON MIDSTREAM, LLC

And

EQT ENERGY, LLC

And

EQT PRODUCTION COMPANY

Dated February 28, 2017

GAS GATHERING AGREEMENT

THIS SIXTH AMENDED AND RESTATED GAS GATHERING AGREEMENT (“ Agreement ”) is entered into as of this 28th Day of February, 2017 (the “ Effective Date ”), by and between RICE POSEIDON MIDSTREAM LLC, a Delaware limited liability company (“ Gatherer ”), EQT ENERGY, LLC, a Delaware limited liability company (“ Shipper ”) and, for limited purposes as set forth herein, EQT PRODUCTION COMPANY a Pennsylvania corporation (“ Producer ”). Gatherer and Shipper may be referenced individually as a “ Party ” or collectively as the “ Parties .”

RECITALS

The predecessors in interest to each Party entered into certain Gas Gathering Agreements, dated March 1, 2011 by and between M3 Appalachia Gathering, LLC and Chesapeake Energy Marketing, Inc. and Chesapeake Appalachia, LLC and by and between M3 Appalachia Gathering, LLC and Statoil Natural Gas, LLC and Statoil Onshore Properties, LLC, as first amended September 6, 2011, as second amended December 12, 2012, and as third amended on January 1, 2015 by successors in interest of Rice Poseidon Midstream LLC and EQT Energy LLC and EQT Production Company. On December 18, 2015, the Parties entered into a Fourth Amended and Restated Gas Gathering Agreement and on April 1, 2016 the Parties entered into a Fifth Amended and Restated Gas Gathering Agreement (the “ Gathering Agreement ”) further amending and restating the prior gathering agreements.


B.	The Parties now desire to further amend and restate the Gathering Agreement as set forth herein in this Agreement.

Shipper purchases all of the gas produced from wells drilled on well pads controlled by Producer or its predecessor in interest as of March 1, 2011 or hereafter acquired by Producer in Allegheny County and Washington County, Pennsylvania, and specifically located within the area of mutual interest as depicted on Exhibit A , as modified pursuant to Section 2.4(a) , (the “ Acreage ”) and desires to deliver to Gatherer all gas produced from the Acreage that Shipper purchases.


D.	Gatherer is developing the Appalachia Gathering System as depicted on Exhibit C (the “ AGS Gathering System ”) and desires to construct the AGS Gathering System to accept deliveries of gas from Shipper at the central delivery points (“ CDPs ”) and redeliver the gas to Shipper at the Redelivery Points (defined below), all as set forth in this Agreement.

Gatherer is developing the Denex Gathering System as depicted on Exhibit C (the “ Denex Gathering System ”) and desires to construct and expand the Denex Gathering System to accept deliveries of gas from Shipper at CDPs and redeliver the gas to Shipper at the Redelivery Points (defined below), all as set forth in this Agreement. The AGS Gathering System and Denex Gathering System may be referenced collectively as the “ Gathering Systems ”.

Therefore, in consideration of the mutual promises set out in this Agreement, and other good and valuable consideration, the receipt and sufficiency of which is acknowledged, the Parties and Producer hereby agree as follows:

1. DEFINITIONS


1.1.	Defined terms . Unless otherwise defined in the recitals or text of this Agreement, capitalized terms are defined in the additional Terms and Conditions contained in Exhibit B attached to, and by this reference made a part of this Agreement, and shall have the meanings respectively ascribed to them therein.

2. NATURE AND EXTENT OF AGREEMENT

2.1.

Commitment . Producer covenants to sell and Shipper covenants to purchase from Producer all of the gas (including natural gas, natural gasoline and other liquefiable hydrocarbons) that Producer owns or controls and produces from the Acreage (“ Dedicated Gas ”). Dedicated Gas shall not include gas produced from well pads located within the Acreage that are not operated by Producer or its Affiliate. Notwithstanding the prior sentence, Dedicated Gas shall always include all gas produced from well pads located within the Acreage that are initially operated by Producer or Shipper but may later become non-operated by Producer or Shipper due to a voluntary or involuntary loss of operatorship. Shipper covenants to deliver all of the Dedicated Gas exclusively to Gatherer at the CDPs without other disposition except as otherwise provided in this Agreement. Shipper may also deliver gas produced from Producer’s wells outside of the Acreage to CDPs located within the Acreage. Such gas shall be excluded from the exclusive dedication of Dedicated Gas made by Shipper in this Section 2.1 during the term of this Agreement, but shall in all other respects be treated on the same terms and conditions as the Dedicated Gas delivered hereunder.

2.2.

Services . Gatherer shall receive the Dedicated Gas at the CDPs and Gatherer will gather, compress and dehydrate such Gas as set forth herein. Gatherer will redeliver such Dedicated Gas, less the Fuel (defined in Exhibit B ), to Shipper at certain interconnect points constructed or to be constructed by Gatherer between the Gathering Systems and certain pipelines, including Texas Eastern Transmission, LP pipelines (“ TETCO ”) at the Tombstone interconnect, Equitrans LP pipeline H-148 (“ EQT ”) at the Jaybird interconnect, Dominion Transmission, Inc. pipeline TL-342 (“ DTI ”) at the California interconnect, M3 Gathering System pipeline (“ M3 ”) at the High Noon interconnect, and Columbia Gas Transmission pipeline (“ TCO ”) at the Kryptonite interconnect, all located or to be located in Washington County and/or Greene County, Pennsylvania, as applicable (such interconnect points, collectively, the “ Redelivery Points ” and individually a “ Redelivery Point ”) subject to Gatherer having available capacity to confirm Shipper’s nominations to such Redelivery Points during the entirety of the Month. As part of the Firm Service (as defined below), Gatherer is obligated to redeliver to Shipper only at the Tombstone interconnect at a maximum of [***] MMBtu per Day, the High Noon interconnect at a maximum of [***] MMBtu per Day, and the California interconnect at a maximum of [***] MMBtu per Day (with aggregate quantities on each Gathering System subject to Gatherer’s applicable maximum receipt obligations for Firm Service set forth in Section 2.2(d)). All quantities

delivered in excess of these Firm Service quantities and quantities to other Redelivery Points will be interruptible service. Shipper shall be solely responsible for arranging the disposition of the gas redelivered to it or for its account at the Redelivery Points.

(a)

AGS Gathering System Firm Service . The total maximum daily volume (“ MDV ”) that Gatherer is obligated to accept into the AGS Gathering System at the CDPs shall equal [***] MMBtu per Day on any Day during the Primary Term and the Extended Term (the “ AGS Gathering System Firm Service ”); provided that notwithstanding the foregoing, Shipper’s AGS Gathering System Firm Service shall at all times be subject to Section 2.2(c) and Section 2.2(d). The AGS Gathering System Firm Service shall not be curtailed, interrupted or discontinued by Gatherer without liability for any reason except for (x) an event of Force Majeure; (y) failure or refusal of Shipper to receive or deliver Gas to or from Gatherer, as applicable, in accordance with this Agreement, and (z) failure or refusal of Shipper to comply with the terms and provisions of this Agreement.

(b)

Denex Gathering System Firm Service . The total MDV that the Gatherer is obligated to accept into the Denex Gathering System at the CDPs, excluding the Trax Farms CDP, collectively shall be equal to [***] MMBtu per Day on any Day during the Primary Term and the Extended Term (the “ Denex Gathering System Firm Service ”); provided that notwithstanding the foregoing, Shipper’s Denex Gathering System Firm Service shall at all times be subject to Section 2.2(c) and Section 2.2(d). Gatherer is not obligated to accept Gas into the Denex Gathering System at the Trax Farms CDP. Shipper’s Denex Gathering System Firm Service shall not be curtailed, interrupted or discontinued by Gatherer without liability for any reason except for (x) an event of Force Majeure; (y) failure or refusal of Shipper to receive of deliver Gas to or from Gatherer, as applicable, in accordance with this Agreement, and (z) failure or refusal of Shipper to comply with the terms and provisions of this Agreement. The AGS Gathering System Firm Service and Denex Gathering System Firm Service may be referenced collectively as “ Firm Service ”. Gatherer acknowledges and agrees that Firm Service is the highest priority level of service on the Gathering System.

(c)

Release . In the event that Firm Service to Shipper is interrupted, curtailed or disrupted for any reason other than as provided in clauses (x), (y) and (z) of Section 2.2(a) or Section 2.2(b) , above (but expressly excluding any failure to meet the runtime requirements in Section 3.4 , below, where the remedy for such failure is expressly set forth therein) for [***] ([***]) Days during any [***] ([***]) period, then Shipper shall be entitled to a temporary release from this Agreement of the Firm Service Gas volumes that Gatherer is unable to accept. Such release shall be conditional for a continuous period beginning on the [***] ([***]) Day of interruption or curtailment during such [***] period, and shall not exceed [***] thereafter. Should Gatherer reestablish regular Firm Service to Shipper during the [***] release period which it does not reasonably believe will be subject to further interruption, Gatherer shall give Shipper written notice of such fact; and, within [***] ([***]) Days after its

receipt of such notice Shipper shall return all released volumes to the Gatherer and such volumes shall no longer be temporarily released from this Agreement. In the event Gatherer fails to reestablish Shipper’s Firm Service within the [***] release period, Shipper shall be entitled to a permanent release from this Agreement, at Shipper’s sole option, of any Firm Service Gas volumes Gatherer is unable accept on a Firm Service basis.

(d)

Reversion to Gatherer for Non-Use . Beginning on October 1, 2015, and continuing each Year thereafter, the Parties shall re-evaluate the MDV for the AGS Gathering System Firm Service at the end of each Year of the Primary Term and Extended Term to provide Shipper with the capacity it requires while affording the Gatherer with the flexibility needed to utilize unused capacity on the AGS Gathering System. The Parties shall adjust the MDV for the following [***] ([***]) Months (the “ MDV Adjustment Period ”) for the AGS Gathering System to equal the sum of (i) no less than [***]% of the average daily quantity received at the CDPs delivering into the AGS Gathering System in the previous [***] ([***]) Months and (ii) no less than [***]% of [***] ([***]) Months of forecasted peak quantity of gas flowing into the AGS Gathering System from new wells not producing during the previous month, but never to exceed the initial MDV of [***] MMBtu per Day unless agreed to in writing by the Parties.

Beginning January 1, 2018, and continuing each Year thereafter, Parties shall reevaluate the MDV for the Denex Gathering System Firm Service. The Parties shall adjust the MDV for the MDV Adjustment Period for the Denex Gathering System to equal the sum of (i) no less than [***]% of the average daily quantity received at the those CDP(s) delivering into the Denex Gathering System in the previous [***] ([***]) Months and (ii) no less than [***]% of [***] ([***]) [***] of forecasted peak quantity of gas flowing into the AGS Gathering System from new wells not producing during the previous month, but never to exceed the initial MDV of [***] MMBtu per Day. Gatherer reserves the right to temporarily bypass required quantities received around compression if Gatherer has insufficient compression to maintain an MDV capacity of [***] MMBtu per Day through compression on the Denex Gathering System. Any such bypass shall be temporary and shall not extend for more than [***] ([***]) [***] from the commencement of flow from any new CDP or commencement of flow from any existing CDP with increased quantity of gas.

Following any decrease in aggregate MDV for the Gathering Systems, the aggregate quantity of gas for which Gatherer is obligated to redeliver to a Redelivery Point as part of Firm Service as set forth in this Section 2.2 shall decrease by a percentage equal to the percentage decrease in aggregate MDV. Such decreased aggregate firm redelivery quantity shall be effective on the same date as the decrease in aggregate MDV and shall be distributed among Redelivery Points in a manner mutually agreed upon by the Parties.

2.3.

Term . This Agreement shall become effective on the March 1, 2011 and remain in full force and effect for a primary term ending January 31, 2021 (“ Primary Term ”) and, upon the expiration of the Primary Term, an additional ten (10) year term ending January 31, 2031 (the “ Extended Term ”). This Agreement shall continue beyond the Extended Term on a year-to-year basis unless otherwise terminated by either party by providing at least [***] ([***]) Days’ written notice.


2.4.	Dedicated Lease Swap .

(a)

As of December 25, 2014, the Parties agreed to the following acreage swap: (i) Gatherer hereby releases certain leases located within the Acreage (the “ Released Leases ”) in consideration of the dedication by Producer of substantially similar leases located within the Acreage (the “ Replacement Leases ”) and (ii) Producer hereby dedicates the Replacement Leases to this Agreement (clauses (i) and (ii) together, the “ Dedicated Lease Swap ”), all as represented by the area of mutual interest set forth in Exhibit D Beginning on December 25, 2014, the Released Leases will no longer be dedicated hereunder and the Replacement Leases will be dedicated to this Agreement for the remainder of the Primary Term and the Extended Term.

3. FACILITIES


3.1.	Shipper’s Construction Responsibilities . Shipper shall be solely responsible for the design, construction, acquisition of rights-of-way, and all costs associated with the construction of pipelines, free liquids removal and handling, and wellhead metering facilities to connect the wells on the Acreage (or outside of the Acreage) to the CDPs.


3.2.	[Intentionally Omitted]

3.3.

Gatherer’s Construction Responsibilities . Gatherer shall own, and shall be solely responsible for the construction, maintenance, and operation of the Gathering System. Gatherer shall install, own and operate the CDPs which shall be located within each Drilling Unit within the Acreage. Gatherer shall not be required to extend the Gathering Systems beyond the Acreage to CDPs that do not qualify as a Drilling Unit (unless requested under Section 3.3(b) below) or install CDPs outside of the Acreage. The general locations of the CDPs are set forth in the attached Exhibit C ; however , the precise locations of each CDP shall be mutually determined by Shipper and Gatherer (the actual location of a CDP as constructed to evidence such agreed location).

(a)

Future Construction. Shipper may request in writing that Gatherer construct additional laterals and pipeline extensions ( “ Future Construction ” ) to connect future CDPs within the Acreage to the Gathering Systems. Gatherer shall work diligently to complete the Future Construction as promptly as commercially reasonable. Additionally, upon securing the required rights-of-way and governmental or regulatory permits, Gatherer shall use commercially reasonable efforts to insure any Future Construction is completed within a timeframe allotting [***] ([***]) weeks for each mile of pipeline to be constructed; provided, that any

pipeline of [***]. In the event that Gatherer does not complete the Future Construction within the time periods described above, and, as a result of such failure, any of Shipper’s CDPs is “waiting on pipeline”, then Gatherer shall credit Shipper’s Service Fee by [***]% for such CDP for an equivalent time period for which the affected CDP was waiting on pipeline. For purposes of this Section 3.3(a), “waiting on pipeline” means that the affected CDP is not operational and able to accept the Dedicated Gas [***] ([***]) Days following the first Day that both (x) Shipper’s construction responsibilities related to such CDP and upstream well are complete and (y) Shipper fractures the well connected upstream of such CDP.

(b)

Shipper may request Gatherer, in writing, to construct additional laterals, pipeline extensions, and meter stations to connect CDPs to the Gathering Systems to lands that are not within a Drilling Unit (as defined herein). Gatherer shall work diligently to complete the construction as promptly as commercially reasonable. Shipper shall reimburse Gatherer for [***]% of Gatherer’s costs incurred in the construction of such laterals, pipeline extensions, and meter stations. Such costs shall [***] include all [***] capital costs incurred including, but not limited to, materials, labor, rights-of-way acquisition costs, permitting costs, and inspector costs. Such reimbursement shall be paid in [***] ([***]) [***]. For any lateral or extension constructed under this Section 3.3(b), Shipper’s Dedicated Gas on such laterals or extensions shall have priority over all other deliveries from other shippers flowing on such laterals or extensions.

(c)

At Gatherer’s sole cost and expense, Gatherer anticipates placing into service facilities necessary to connect the Denex Gathering System to the Harbison CDP by July 15, 2018 and the Redd CDP [***] ([***]) months after the Redd CDP commences flow, and will attempt to connect earlier based on a commercially reasonable basis. Once the connection to the Harbison CDP is completed, the Shipper’s MDV for the Denex Gathering System will be increased to [***] MMBtu/Day. A general description of such facilities are as follows:

(i)

Gatherer shall construct, or cause its Affiliate to construct, approximately [***] ([***]) miles of gathering pipeline to service EQT’s wells. Specifically, for the Harbison Well and Lutes Well , Gatherer shall construct, or cause its Affiliate to construct, approximately [***] [***] miles of pipeline loop from the area in proximity to the Harbison Well to the eastern end of the Denex Gathering System. For the Redd Well, Rice shall construct an approximately [***] ([***]) mile of gathering pipelineto transition the Redd Well to the suction of compression towards the middle of the Denex Gathering System. Notwithstanding anything else in this Section 3.3(c)(i), Gatherer shall have sole discretion over the construction of the facilities necessary to satisfy its obligations in this Section 3.3(c).


3.4.	Run Time . Gatherer shall endeavor to maintain the run time of its facilities at [*] percent ([*]%) per Month on an hourly basis; provided, however , such run time calculation shall

not include time lost due to Force Majeure or Gatherer’s [***] maintenance of its facilities. Gatherer and Shipper shall determine, once every [***] ([***]) [***] whether the run time during the previous [***] ([***]) [***] was less than [***]% during the entirety of such period. If Gatherer and Shipper determine that the run time is less than [***]% for such period, and if as a result of such run time Gatherer was unable to provide Firm Service up to the Shipper’s MDV in any Month during such period, then Gatherer shall credit Shipper [***] ($[***]) per Mcf for all gas delivered at the CDPs during the ensuing [***] ([***]) [***] Period up to the quantity of Shipper’s Dedicated Gas Gatherer was not able to deliver. Gatherer shall give Shipper [***] ([***]) Days’ notice of any such planned preventative maintenance of its facilities.

3.5.

AGS Gathering System Pressure . Gatherer shall endeavor to maintain a pressure at each CDP delivered into the AGS Gathering System located within the Acreage of no greater than [***] psi. To calculate the average AGS Gathering System pressure, Gatherer shall take the summation of the average daily pressure from each CDP delivering into the AGS Gathering System over each Month and divide by the aggregate number of CDPs. In the event the pressure at any CDP within the Acreage averages between [***] psi and [***] psi during any given Month, then Gatherer shall credit Shipper [***] ($[***]) per MMBtu for the gas affected during the given Month. In the event the pressure at any CDP within the Acreage averages greater than [***] psi during any Month, then Gatherer shall credit Shipper [***] ($[***]) per MMBtu for the gas affected during the given Month; provided that if the average Daily gas volumes delivered by Shipper to Gatherer at all CDPs and redelivered by Gatherer to Shipper at all Redelivery Points for such Month were in excess of the MDV, then Gatherer shall have no obligation to credit Shipper for such Month. Notwithstanding anything in this Agreement to the contrary, commencing on January 1, 2015 and continuing Month to Month thereafter until the date that is [***] ([***]) [***] after the Day Shipper notifies Gatherer in writing that it will not, for the remainder of the Primary Term or Extended Term, deliver to the AGS Gathering System volumes of gas in excess of the volumes being then presently produced from wells within the Acreage (and provided that average Daily volumes of gas delivered by Shipper during such [***] ([***]) [***] period are less than or equal to the volumes of gas delivered by Shipper on the date of such notification), Shipper waives and releases Gatherer from the obligation to credit Shipper for gas received within the Acreage during any Month that has an average AGS Gathering System pressure of less than [***] psi for such Month; provided that the termination of such waiver and release will not become effective until Shipper delivers, for an uninterrupted [***] ([***]) [***] period, Daily average volumes of gas that are less than or equal to the volumes of gas delivered by Shipper on the date of such notification. No pressure obligations shall apply to the Denex Gathering System and Gatherer will use commercially reasonable efforts to maintain a pressure at each CDP delivering into the Denex Gathering System of no greater than [***] psig.


3.6.	Buy-Back Meter .


(a)	Installation . At the written request of either Producer or Shipper, Gatherer shall provide Producer with a cost estimate and plans for the procurement and installation

of one or more buy-back meters on the Gathering Systems for Producer’s drilling operations (each, a “ Buy-Back Meter ”) within [***] ([***]) [***] of receiving each such request; provided that, for a [***] ([***]) period after receiving Gatherer’s cost estimate and project plans, Producer may request reasonable changes to Gatherer’s cost estimate and/or project plans to be implemented with Gatherer’s consent, which consent shall not be unreasonably withheld, conditioned or delayed. If Producer agrees to any such cost estimate and project plans, Gatherer shall install each such Buy-Back Meter at the location specified in the project plans. Acknowledging that time is of the essence, Gatherer shall work diligently to complete the installation in a commercially reasonable manner and on an [***], reimbursable basis. Producer shall reimburse Gatherer for 100% of Gatherer’s costs incurred in the installation of any such Buy-Back Meter, which costs shall (i) [***] (ii) include all auditable costs incurred by Gatherer during such installation, including but not limited to costs for equipment, materials, labor, permitting, inspection and maintenance. Producer shall be responsible for any taxes or fees levied on Gatherer for this service. Gatherer shall own, operate, and maintain all facilities installed as part of each Buy-Back Meter. Once each Buy-Back Meter project is complete and Gatherer has accrued all costs, Gatherer will invoice Producer for all such costs and include reasonable documentation to justify all costs. Producer shall remit the invoiced amount on the date that is the later of the 25th Day of the Month following the Accounting Period or thirty (30) Days after the date of such invoice.

(b)

Operation . Producer shall be solely responsible for all costs and operations downstream of each Buy-Back Meter, including but not limited to using each such Buy-Back Meter to remove gas from the Gathering System. Any such gas removed by Producer shall be deemed to be pre-delivered to Shipper from Shipper’s account and such Buy-Back Meter shall be deemed a Redelivery Point for all purposes hereunder except with respect to Gatherer’s obligation to provide Firm Service at any such Buy-Back Meter Redelivery Point; the Parties acknowledge that Gatherer will only provide interruptible service at any such Buy-Back Meter Redelivery Point. The gas removed by Producer shall constitute a loan of an equivalent quantity of gas, in MMBtus, from Shipper to Producer; provided that (i) Producer shall repay to Shipper such loaned amount in-kind as soon as possible and (ii) all subsequent deliveries of gas by Shipper at the CDPs shall be deemed to repay any imbalance in Shipper’s account until the same quantity of MMBtus pre-delivered to Producer is fully restored to Shipper’s account. PRODUCER AND SHIPPER SHALL RELEASE, INDEMNIFY AND HOLD GATHERER HARMLESS FROM ANY AND ALL COSTS, FEES, TAXES, LOSSES AND DAMAGES RELATED TO ANY BUY-BACK METER.

4. FEES


4.1.	Service Fees . The gathering and dehydration fee, the compression fee, and the interconnect fee are collectively referenced in this Agreement as the “ Service Fee ”

(a)

Gathering and Dehydration Fee . Shipper shall pay a gathering and dehydration fee of [***] ($[***]) per MMbtu for all gas delivered to the CDPs into the Gathering Systems provided, however , that until the date that the TETCO Redelivery Point is in service and available for the redelivery of Shipper’s gas (and regardless of Shipper’s nominations, if any, to such Redelivery Point), the gathering and dehydration fee shall be [***] ($[***]) per MMBtu for all gas delivered into the CDPs. Upon Shipper’s delivery of [***] MMBtu per Day during any Month at any or all of the CDPs delivering into the AGS Gathering System, the applicable gathering and dehydration fee for all gas delivered at all CDPs shall be reduced by [***] ($[***]) per MMBtu for the remainder of the Primary Term and Extended Term.

(b)

Compression Fee . Shipper shall pay [***] ($[***]) per MMBtu for compression fee for all gas delivered to the CDPs into the AGS Gathering System (“ AGS Compression Fee ”) and Shipper shall pay [***] ($[***]) per MMBtu for compression fee for all gas delivered to the CDPS into the Denex Gathering System (“ Denex Compression Fee ”). No Denex Compression Fee shall be assessed to a CDP when Gatherer has that specific CDP on bypass of compression as permitted by Section 2.2(d) of this Agreement.

4.2.

Fuel . Shipper shall be allocated its pro rata share of the actual Fuel in MMBtus for each Gathering System. The lost and unaccounted for gas component of the Fuel allocated to Shipper shall not exceed [***] ([***]%) of Shipper’s Dedicated Gas delivered at the CDPs delivered into each Gathering System (measured in MMBtus) during any [***] ([***]) [***] period. If applicable, the compression component of the Fuel allocated to Shipper shall not exceed [***] ([***]%) of Shipper's Dedicated Gas per stage of compression performed by Gatherer in any [***].

4.3.

CPI Adjuster . All Service Fees, except the Denex Compression Fee, shall be adjusted upward or downward, annually, for inflation or deflation on each January 1, beginning January 1, 2013 by multiplying each Service Fee by the sum of (a) one, plus (b) the percentage increase or decrease, if any, in the final Consumer Price Index for All Urban Consumers U.S. City Average, All Items, Not Seasonally Adjusted (“ CPI-U ”) (as reported by the United States Department of Labor, Bureau of Labor Statistics) for the previous twelve-Month (12-Month) period for which changes are reported; provided, however , that in no event will the Service Fee ever be reduced below the amounts set forth in Section 4.1 . For purposes of this Section 4.3 , the CPI-U shall not exceed [***]% per year. The Denex Compression Fee and Interconnect Fee will be adjusted by the same mechanism on each January 1, beginning January 1, 2017.

5. NOTICES

5.1.

Notices . Unless expressly specified otherwise in this Agreement, all notices, demands or communications (“ Notices ”) under this Agreement shall be in writing and shall be addressed to the party as set forth in this Section 5. Notices shall be deemed effective and shall be deemed delivered (i) if by personal delivery or by overnight courier, on the date of delivery if delivered on or before 4:30 p.m. local time on such Day, (ii) if by electronic communication,

on the Day of receipt unless received after 4:30 p.m. local time, and (iii) if by mail, on the first to occur of actual receipt or the third business Day following the date of posting (as evidenced by the postal receipt). Unless otherwise changed by Notice to the other party, all Notices shall be addressed as follows:

If to Shipper:

EQT Energy, LLC

625 Liberty Ave.

Suite 1700

Pittsburgh, PA 15222

Attn: [***]

Phone: [***]

Email address: [***]

If to Producer:

EQT Production Company

625 Liberty Ave.

Suite 1700

Pittsburgh, PA 15222

Attn: [***]

Phone: [***]

Email address: [***]

If to Gatherer:

Rice Poseidon Midstream LLC

2200 Rice Drive

Canonsburg, PA 15317

Attn: [***]

Phone: [***]

Fax: [***]

Email address: [***]

IN WITNESS WHEREOF, the parties have executed this Agreement to be effective as of the Effective Date.

Shipper Gatherer

EQT ENERGY, LLC RICE POSEIDON MIDSTREAM LLC



By: /s/ Donald M. Jenkins	By: /s/ Rob Wingo
Name: Donald M. Jenkins	Name: Rob Wingo

AGREED TO for the purposes set forth in this Agreement:

Producer

EQT PRODUCTION COMPANY

By: /s/ David Schlosser

Name: David Schlosser

Title: EVP

EXHIBIT A

AREA OF MUTUAL INTEREST

[***]

EXHIBIT B

GENERAL TERMS AND CONDITIONS

1. DEFINITIONS


1.1.	Defined Terms . The following terms, when capitalized in the Agreement and/or this Exhibit B , shall have the meanings defined either in this Section 1.1 , or shall have the meanings ascribed to them elsewhere in the text of this Agreement.

“ Accounting Period ” means a period of one Month during which deliveries are made by Shipper at the CDPs.

“ Affiliate ” means any Person that, directly or indirectly through one or more intermediaries, controls or is controlled by or is under common control with another Person. Affiliated shall have the correlative meaning. The term “control” (including its derivatives and similar terms) shall mean possessing the power to direct or cause the direction of the management and policies of a Person, whether through ownership, by contract, or otherwise. Notwithstanding the foregoing, any Person shall be deemed to control any specified Person if such Person owns or controls fifty percent (50%) or more of the voting securities of the specified Person, or if the specified Person owns or controls fifty percent (50%) or more of the voting securities of such Person, or if fifty percent (50%) or more of the voting securities of the specified Person and such Person are under common control

“ Btu ” or “ BTU ” means British Thermal Unit and is defined as the amount of heat required to raise the temperature of one (1) avoirdupois pound of pure water from fifty nine and one-half degrees Fahrenheit (59.5°F) to sixty and one-half degrees Fahrenheit (60.5°F) at a constant pressure of fourteen and seventy three hundredths pounds per square inch absolute (14.73 Psia).

“ Cubic Foot of gas ” means the amount of gas required to fill a cubic foot of space when the gas is at a base pressure of 14.73 Psia at a base temperature of sixty degrees Fahrenheit (60° F).

“ Day ” means the 24-hour period beginning and ending at 9:00 a.m. local time. The reference date for any Day shall be the calendar date at the beginning of the Day.

“ Drilling Unit ” means [***] or such other quantity of contiguous acres of land within the Acreage that is formed and permitted for natural gas drilling and production by Producer.

“ Force Majeure ” shall have the meaning set forth in Section 10 of this Exhibit B .

“ Fuel ” means gas volumes or electrical power consumed and gas volumes incidentally lost and unaccounted for in the operation of the Gathering Systems and the provision of the compression, dehydration and other services that are contemplated by this Agreement.

“ Gas ,” whether or not capitalized herein, means the effluent vapor including all of the constituents thereof and entrained liquids as produced from a well, whether a gas well or an oil well, and delivered into the Gathering System by Shipper and other producers at their respective CDPs.

“ Law(s) ” means all present and future valid applicable laws, rules, regulations, ordinances, decrees, decisions or orders of any federal, state or local governmental authority.

“ Mcf ” means one thousand (1,000) cubic feet of gas.

“ MMBtu ” shall mean one million (1,000,000) Btus.

“ Month ” means a period beginning at 9:00 a.m. on the first Day of a calendar month and ending at 9:00 a.m. on the first Day of the next succeeding calendar month.

“ Psia ” means pounds per square inch absolute.

“ Psig ” means pounds per square inch gauge.

“ Year ” means the period of time beginning at 9:00 a.m. local time on one Day and ending at 9:00 a.m. local time on the same Day the following year.

2. REPRESENTATIONS, WARRANTIES AND COVENANTS

2.1.

General Representations and Warranties . As of May 31, 2013 for Shipper and Producer and as of February 12, 2014 for Gatherer, and during the term of this Agreement, each party, as to itself only, represents and warrants that: (a) it has the right, power, authority and capacity to enter into and perform this Agreement and all transactions contemplated herein, and all actions required to authorize it to enter into and perform this Agreement have been properly taken; (b) there are no bankruptcy, insolvency, reorganization, receivership or other arrangement proceedings pending or being contemplated by it; (c) there are no pending or threatened lawsuits, proceedings, judgments or orders by or before any court or governmental authority that affect either its ability to perform this Agreement or the rights of the other party hereunder.

2.2.

Warranty of Title and Covenant to Defend . Shipper hereby warrants that at the time of delivery of Shipper’s Dedicated Gas to the CDPs it will have good title to or the right to deliver the gas delivered hereunder and Shipper’s right to sell the same, or market said gas free from all liens and adverse claims, including liens to secure payment of production taxes, severance taxes, and other taxes. Shipper shall defend and indemnify Gatherer and save it harmless from all suits, actions, debts, accounts, damages, costs, losses and expenses arising from or out of adverse claims, whether meritorious or not, of any and all Persons relating to ownership of said gas or to royalties, overriding royalties, taxes, license fees, or charges thereon, resulting from actions of, by, or through or under Shipper. Gatherer shall be entitled to recover all reasonable attorneys’ fees incurred as a result of its involvement in any action or claim described herein.


2.3.	Redelivery of Gas . Shipper covenants to accept or otherwise make suitable arrangements for the disposition of its gas at the Redelivery Points. Upon Shipper’s failure to do so, Gatherer shall be immediately entitled to discontinue receipt of the Shipper’s Gas until Shipper is able to make such suitable arrangements.

2.4.

Operational Nomination and Balancing . Nominations are to be submitted by Shipper to the attention of Gatherer’s gas scheduling department in writing, by electronic means designated by Gatherer by 11:30 a.m. Central Time on the Day before Gas is to flow. The nominations shall cite the aggregate volume of gas by system, adjusted for Fuel, as applicable, to be delivered by Shipper at the CDP(s) for redelivery by Gatherer at specified Redelivery Point(s), all in accordance with Gatherer’s then current nomination procedure. Gatherer shall notify Shipper of differences in nominated and scheduled quantities in a timely manner on the Day the nomination is made.

If during any Month, Gas received into Gatherer’s System by or on behalf of Shipper is greater or less than Gas delivered for or on behalf of Shipper, given due adjustments for Fuel, such imbalance shall be resolved on a monthly basis with the same imbalance resolution methodology utilized by the downstream pipeline. All outstanding imbalances shall be resolved within [***] ([***]) Days of the termination of this Agreement.

Notwithstanding anything to the contrary herein, Shipper and Gatherer agree that the operational nomination and balancing provisions set forth herein take into account the policies of the pipelines connected to the downstream side of the Redelivery Points as of March 1, 2011. In the event such policies change after March 1, 2011, Shipper and Gatherer agree to modify the procedures set forth above to comply, in all respects, with such downstream pipeline policies and procedures.

2.5.

Agreement for Grant of Easement . To the extent that Shipper or any of its Affiliates owns any surface property in fee or pursuant to a leasehold interest, Shipper shall, without cost to Gatherer and to the extent it has the right to do so, grant, assign or convey, or request the Affiliate to grant, assign or convey, to Gatherer an easement and right-of-way over, under and across such property, and through any adjoining lands in which Shipper may have an interest, for the purpose of installing, using, inspecting, repairing, operating, replacing, and/or removing Gatherer’s pipe, meters, lines, and other equipment used or useful in the performance of the Agreement. Any property of Gatherer placed in or upon any of such land shall remain the personal property of Gatherer. Gatherer shall indemnify and hold Shipper harmless of and from any and all claims and damages for all injuries to persons, including death, or damage to property arising out of or incident to Gatherer’s use of the easement hereunder transferred, only in the event said claim or damage shall be the result of the negligence of Gatherer, their employees, agents and representatives.

3. POINT(S) OF DELIVERY, PRESSURE AND OWNERSHIP

3.1.

Points of Delivery and Redelivery . The inlet block valve flange of Gatherer’s metering facilities located at a CDP is the point of delivery for all of the Shipper’s Gas delivered into the applicable Gathering System at such CDP. The outlet block valve flange of Gatherer’s metering facilities located at a Redelivery Point is the point of redelivery for all of the Shipper’s Gas delivered at such Redelivery Point.


3.2.	Transfer of Title . Title to all of the Shipper’s Gas shall remain with Shipper and shall not pass to Gatherer, unless otherwise provided in this Agreement.

3.3.

Possession and Control . Shipper shall be in possession and control of the gas deliverable under the Agreement and responsible for any injury or damage caused thereby until the same shall have been delivered to Gatherer at the CDPs. Gatherer shall be deemed to be in exclusive possession and control of the gas once it is received at the CDPs until redelivery at the Redelivery Points, and responsible for any injury or damage caused thereby.


3.4.	Uniform Rate of Flow . The parties recognize the desirability of maintaining a uniform rate of flow of gas to the Gathering Systems, and Shipper agrees to use its best commercially reasonable efforts to regulate its delivery of Shipper’s Gas so that gas shall be made available at the CDPs at as uniform a rate of flow as practicable.

3.5.

Pressure . Shipper shall deliver gas, or cause gas to be delivered, at the CDPs at pressures sufficient to affect delivery into the Gathering Systems, but in no event shall Shipper cause the pressure at the CDPs to exceed the maximum allowable operating pressure (“ MAOP ”) as determined by Gatherer. Shipper shall also install and operate, or cause to be installed and operated, an automatic high pressure shutoff valve on the equipment at each CDP to shut off gas flow at a maximum pressure as determined by Gatherer from time to time to limit the pressure at which Shipper delivers gas to prevent the over-pressuring of the Gathering System for safety purposes.

4. RESERVATIONS OF SHIPPER OR PRODUCER

4.1.

Excluded Gas . Shipper or Producer hereby expressly reserves the following rights with respect to Shipper’s or Producer’s Gas and the Acreage prior to delivery of the same to Gatherer at the CDPs: (a) to use the gas for fuel in the development and operation of the leases from which the gas is produced; (b) to provide the gas for delivery to unaffiliated lessors of the leases of the gas if such lessors are entitled to use or take such gas in kind under the terms of the leases, provided however, that such gas is not delivered to the lessors via Gatherer’s Gathering Systems; (c) to use the gas for fuel or lift gas in the operation of the facilities which Shipper may install in order to deliver gas hereunder in accordance with the terms hereof; (d) to pool or unitize the leases (or any portion thereof) with other lands and leases; provided , that, this Agreement will cover Shipper’s interest in the pool or unit and the gas attributable thereto; and (e) [***].

5. QUANTITY RESTRICTIONS

5.1.

Obligation to Receive Gas . Shipper acknowledges and understands that Gatherer will use the Gathering Systems to receive gas delivered by other parties and that Gatherer has the right to designate or utilize gathering, compression or dehydration facilities owned and operated by third parties to gather, compress, and dehydrate the Shipper’s Gas. Gatherer’s obligation to receive the Shipper’s Gas under the Agreement is subject to the limitations and conditions set forth below:

(A)

Restrictions . If Gatherer is unable to receive the total volumes of the Gas due to any event of Force Majeure, Gatherer shall use its commercially reasonable efforts to control and receive only that portion of the Gas available for delivery from each CDP which is ratable on a volumetric basis with the total volumes subject to such restrictions and available for delivery from all CDPs on the Gathering Systems based upon the most recent Accounting Period of production during which no events of Force Majeure were in effect.


(B)	Unacceptable Gas . Gatherer shall not be required to accept gas from any CDP where Gatherer reasonably believes an unsafe condition exists or where such gas does not meet the quality specifications set forth in Section 7.1 .

6. GAS MEASUREMENT

6.1.

Measurement Equipment . Gatherer shall furnish and install at the CDPs a suitable Senior orifice meter run, and other ancillary devices as needed, such as transmitters and flow computers, or other types of meter or meters of standard make and design commonly acceptable in the industry and meter design where the facility will not require a shutdown to perform meter calibration, at the CDPs. Each meter installed shall be a meter acceptable in the industry and each meter shall be fabricated, constructed, installed, and operated in accordance with the requirements of applicable provisions in American Gas Association (“ AGA ”) - American Petroleum Institute (“ API ”) AGA 2000 I API 14.3 specifications, and American National Standards Institute (“ ANSI ”) - API ANSVAPI 2530, “ Orifice Metering of Natural Gas ” (AGA gas Measurement Committee Report No. 3) of the Natural Gas Department of the AGA, Electronic flow measurement shall comply with API 21.1, Flow Measurement Using Electronic Metering Systems, in effect at the time of installation, as amended from time to time, or by any other method commonly used in the industry and mutually acceptable to the parties. Chart recorded measurement should not be installed or accepted as primary measurement without mutual agreement by both parties. Any meter installed hereunder shall be open to inspection by Shipper at all reasonable times. The charts, electronic flow measurement (“ EFM ”) data and/or records pertaining to measurement hereunder shall be retained by Gatherer for a period of [***] ([***]) [***] (or longer to the extent required by Law) for the mutual use of the parties.

6.2.

Shipper’s Check Meters . Shipper may, at its option and sole expense, install, maintain and operate check meters of a suitable type and other equipment to check Gatherer’s meters; provided, however , that such check meters and other equipment shall be installed by Shipper so as not to interfere with the operation of any of Gatherer’s facilities. Gatherer and Shipper shall have access to each other’s measuring equipment at all times during business hours, but the reading, calibrating and adjustment thereof and the changing of charts shall be done only by the employees or agents of Gatherer and Shipper, respectively, as to meters or check meters so installed hereunder. If EFM is installed by Shipper, Shipper shall allow Gatherer to connect to it and access all relevant data.


6.3.	Meter Calibration .

(A)

Calibration . Gatherer shall calibrate meters as often as required, as determined by Gatherer in accordance with standard industry practices to reasonably assure accurate measurement, but at least twice per year. Calibrations of meters will be made in the presence of representatives of Shipper, if Shipper chooses to be represented. If either party, at any time, desires a special test of any of the meters, the party will promptly notify the other party, and the parties will then cooperate to secure a calibration test and a joint observation of any adjustments, and the meter shall then be adjusted to accuracy. The costs of special tests shall be borne by the requesting party unless the meter is found to be more than [***] percent ([***]%) in error, in which case Gatherer shall pay the costs. Gatherer shall give Shipper notice of the time of all regular tests of its meters and other tests, sufficiently in advance to allow Shipper to have its representative present. Orifice plate inspection will be made at each meter calibration.


(B)	Errors Less Than or Equal to [*]%. If upon any test, any of Gatherer’s measurement equipment is found to be in error by [] percent ([**]%) or less, previous recordings of such equipment shall not be adjusted by the amount of the error, but such equipment shall be adjusted to a condition of accuracy.

(C)

Errors Greater Than [***]% . If, upon any test, any of Gatherer’s measurement equipment is found to be inaccurate by greater than [***] percent ([***]%), and the total inaccuracy is greater than [***] MCF [***], then the registrations and billings shall be corrected for a period from the beginning of the Accounting Period in which the test was conducted, using the order of preference set forth in Section 6.4 below. Following any test, measurement equipment found inaccurate shall be adjusted to a condition of accuracy.

6.4.

Measurement Equipment Out of Service or Repair . If Gatherer’s measurement equipment is found to be measuring inaccurately and the amount of gas delivered cannot be ascertained or computed from the reading, then the gas delivered during the Accounting Period shall be estimated and agreed upon by the parties based on the best data available, using the first available of (i) the registration of any check meter, including Shipper’s Check Meters, or meters if installed and accurately registering; or, (ii) correction of the errors, if the percentage of error is ascertainable by meter calibration, test or mathematical calculation; or (iii) estimation based on comparison of the quantity of deliveries with deliveries during preceding periods under similar conditions when the meter was registering accurately.

6.5.

Standards for Computations . All fundamental constants, observations, records, calculations, and procedures involved in the determination and/or verification of the quantity and other characteristics of gas measured hereunder, for CDP measurement purposes, unless otherwise specified herein, shall be in accordance with the applicable provisions in ANSI - API ANSI/API 2530, “ Orifice Metering of Natural Gas ” (AGA Gas Measurement Committee Report No. 3) as amended from time to time, or by any other method commonly used in the industry and mutually acceptable to the parties. Factors required in the computations shall be determined in the following manner:

(A)

Temperature . The temperature of gas flowing through each meter shall be determined by a recording thermometer or EFM installed by Gatherer (at its sole cost and expense) to properly record the temperature of the flowing gas and the arithmetical average of the temperature recorded while the gas is flowing during each meter chart interval shall be used in correcting volumes delivered hereunder to a temperature base of sixty degrees Fahrenheit (60°F).


(B)	Base Pressure . The base pressure that shall be used for all gas measurement hereunder shall be 14.73 Psia.


(C)	Barometric Pressure . The average absolute atmospheric (barometric) pressure shall be assumed to be 14.40 Psia regardless of the actual elevation or location of the CDP above sea level or of a variation of barometric pressure from time to time.


(D)	Unit of Measurement . The unit of gas volume measurement shall be a MCF of gas. If the pressure base is changed or modified from 14.73 Psia by any regulatory agency having jurisdiction, the unit of measurement shall be adjusted to conform to the new pressure base by use of a factor, the numerator which is 14.73 Psia and the new pressure base (expressed in Psia) is the denominator.

(E)

Deviation from Ideal Gas Laws . Deviation from Ideal Gas Laws shall be determined in accordance with the formulas prescribed in AGA Report No. 8 or other approved methods. The pressure and temperature data shall be taken by appropriate methods, and deviation from Ideal Gas Laws shall be calculated. The accuracy of the super-compressibility factors determined shall be verified once each year, or more often if necessary, and such factors shall be determined in accordance with the AGA Report No. 8 or other approved methods.

6.6.

Gas Analysis . The heating value and specific gravity of the gas shall be determined using chromatographic methods as often as required, using representative spot samples or continuous samplers as determined by mutually agreed between Shipper and Gatherer in accordance with standard industry practice, to reasonably assure accurate determinations, [***]. The tests shall determine the heating value and specific gravity to be used in computations in the measurement of natural gas received by Gatherer until the next regular test, or until changed by special test. For purposes of determining heating value, all gas measured shall be based on actual water vapor content at delivered pressure and temperature conditions. No heating value will be credited for Btus attributable to hydrogen sulfide or other nonhydrocarbon components. Shipper may obtain comparative samples and may connect in parallel for samples. Comparative cylinders are to be connected and/or removed at the same time as Gatherer’s sample.

6.7.

Electronic Flow Measurement . Gatherer may install EFM devices to measure all or part of the gas delivered pursuant to the Agreement. If the EFM equipment is installed, it shall be utilized, and volumes shall be calculated in accordance with generally accepted industry standards. Shipper shall be provided access to the relevant EFM data from Gatherer’s flow measurement equipment. Any cost or expense incurred by Shipper to receive such data shall be the sole responsibility of Shipper.


6.8.	New Measurement Techniques . If at any time a new industry accepted method or technique is developed with respect to gas measurement or the determination of the factors used in such gas measurement, such new method or technique may, at Gatherer’s sole election, be substituted.

7. GAS QUALITY

7.1.

Gas Quality Requirements . The gas received by Gatherer hereunder at each CDP shall be commercial in quality, and free of all odor and deleterious substances injurious to pipelines (including dust, dirt, gum-forming constituents, free water, bacteria, and other liquid or solid matter that might interfere with its merchantability or cause injury to or interference with proper operations of the facilities through which the gas flows). Concentrations of hazardous substances must not be hazardous to health, injurious to pipeline facilities, or a limit to marketability. Hazardous substances shall be defined as toxic substances, carcinogenic substances, and/or reproductive toxins. The Shipper’s Gas delivered at the CDPs shall always conform to the specifications of the pipelines connected to the downstream side of each of the Redelivery Points, as the same may be modified or revised from time to time, and shall initially conform to the following specifications:


(A)	Hydrogen Sulfide – not contain more than one-half (1/2) of a grain per one hundred (100) cubic feet, or 8 parts per million (8 PPM).


(B)	Total Sulfur – not more than five (5) grains per one hundred (100) cubic feet.


(C)	Flowing Gas Temperature – not less than forty degrees (40°F) Fahrenheit nor more than one hundred twenty degrees (120°F) Fahrenheit.


(D)	Heating Value – the gross heating value shall not be Jess than 967 BTU per standard cubic foot on a saturated basis at a base pressure of 14.73 Psia or greater than 1100 BTU per standard cubic foot on a saturated basis at a base pressure of 14.73 Psia.


(E)	Wobbe Number – not less than 1314 nor greater than 1400 or current TETCO Wobbe specifications in effect (calculated using Total Heating Value (THV), dry, under standard conditions at 14.73 psia at 60 degrees (60°F) Fahrenheit.


(F)	Water – there shall not be any free water.


(G)	Oxygen – not more than one tenth of one percent (0.1%) by volume.


(H)	Nitrogen and Oxygen Content – not more than two and seventy-five hundredths percent (2.75%) by volume.


(I)	Carbon Dioxide (CO2) – not more than two percent (2%) by volume.


(J)	Total Non-Combustible Gases – not more than four percent (4%) by volume.


(K)	Hydrocarbon Dewpoint – not more than fifteen degrees (15°) Fahrenheit.

Notwithstanding anything to the contrary herein, Shipper and Gatherer agree that the gas quality specifications set forth above take into account the (i) specifications of the pipelines connected to the downstream side of the Redelivery Points as of March 1, 2011 and (ii) services currently contemplated under this Agreement. Shipper agrees that where any of the downstream pipelines specifications are such that that the services provided under this Agreement as of March 1, 2011 will not result in Shipper’s Gas conforming to such downstream pipeline specifications, then Shipper’s Gas shall be treated in accordance with the nonconforming gas provisions set forth in Section 7.2 , below.


7.2.	Nonconforming Gas .

(A)

Free Flow of Gas . Shipper shall cause its gas to meet the quality specifications contained in this Article and insure that the gas contains no free liquids (except fluids entrained in the gas phase) and solids that could accumulate in Gatherer’s pipelines and impede the free flow of gas. Gatherer shall be responsible and shall make no additional charge to Shipper for the disposal of water, fluids and solids collected through mechanical means. Gatherer shall remit to Shipper all of its pro rata share of the Condensate Proceeds from any sale of liquid hydrocarbons (including condensate and drip liquids) so collected from only the AGS Gathering System and allocated to Shipper on an inlet MMBtu basis. As used herein, “ Condensate Proceeds ” means the actual proceeds received by Gatherer from the sale of condensate collected from the Gathering Systems after deducting Gatherer’s allocation of capital expenses directly incurred or made by Gatherer to collect, remove, treat, condition, store, or transport such liquids, including water and condensate, operating and direct expenses such as personnel costs, chemical costs, and disposal costs, taxes, fees, and adjustments, including, but not limited to, transportation, marketing, loading, third party blending or treating fees, commissions, fuel, losses, freight allowances and adjustments for product quality incurred or made by Gatherer in connection with the sale of said condensate.

(B)

Testing . Gatherer may test the Dedicated Gas for adherence to the specifications contained in this Article. Such testing shall take place at or near the applicable CDP, and shall be in accordance with generally accepted industry standards and procedures. If the Dedicated Gas does not meet the specifications set forth in Section 7.1 above, Gatherer, at its option, may accept or refuse to accept delivery of said gas into the Gathering Systems. Gatherer’s acceptance of such nonconforming Dedicated Gas shall not constitute a waiver of this provision with respect to any future delivery of gas by Gatherer. If Gatherer declines to accept any Dedicated Gas, Shipper shall make reasonable efforts to cause the nonconforming Dedicated Gas to be altered to conform to the quality specifications set forth in Section 7.1 , above. Shipper shall give Gatherer notice of the actions taken to meet the specifications. If Shipper’s nonconforming Dedicated Gas is delivered into Gatherer’s pipeline without the prior knowledge or approval of Gatherer, Shipper shall be liable for any damage or injury to any meters, equipment or other facilities of Gatherer caused by Shipper or its agents.

(C)

Remedial Action . Notwithstanding the foregoing, in the event that the Gas does not conform to the quality specifications set forth in this Article, Gatherer shall have the sole right but not the obligation to install facilities necessary to cause the nonconforming gas to conform thereto. In such event, Gatherer shall charge, and Shipper agrees to pay, additional fees and fuel allowances as the same shall be determined by both parties in good faith, as consideration for such corrective services.

8. TAXES

8.1.

Shipper shall pay or cause to be paid, and agree to indemnify and hold harmless Gatherer from and against the payment of, all excise, gross production, severance, sales, occupation, and all other taxes, charges, or impositions of every kind and character required by statute or by any Governmental Authority with respect to Shipper’s Dedicated Gas [***]. Subject to Section 8.2 , Gatherer shall pay or cause to be paid all taxes and assessments, if any, imposed upon Gatherer for the activity of gathering of Shipper’s Dedicated Gas [***].

8.2.

Shipper shall reimburse Gatherer for [***] (a) any additional, increased, or subsequently applicable taxes (other than income taxes and any real or personal property or other ad valorem tax imposed on Gathering Systems) implemented or imposed after March 1, 2011 that are lawfully levied on or paid by Gatherer with respect to its performance under this Agreement or on any part of Gathering Systems and (b) any new or subsequently applicable assessments, fees or other charges implemented or imposed on Gatherer with respect to the services provided hereunder, including any such assessments, fees or other charges arising from any carbon tax or cap and trade law, rule or regulation adopted after March 1, 2011. [***]. [***]. If any Governmental Authority takes any action (including issuance of any “policy statement,” rule, or regulation) whereby the receipt, gathering, treating, or delivery of Shipper’s gas as contemplated under this Agreement shall be prohibited or subject to terms, conditions or regulations, including rate or price controls or ceilings or open access requirements not in effect on March 1, 2011, and which, in the reasonable judgment of Gatherer, materially adversely affect the economics of the services provided, and Fees received, under this Agreement, then, upon notice by Gatherer to Shipper, the Parties shall as promptly as practicable meet to negotiate in good faith such changes to the terms of this Agreement as may be necessary or appropriate to preserve and continue for the Parties the rights and benefits originally contemplated for the Parties by this Agreement, including returns expected by Gatherer, with such amendment to this Agreement to be effective no later than the effective date of such new or amended applicable law.

9. BILLING PERIOD, STATEMENTS, and PAYMENT

9.1.

Gatherer’s Invoice . After delivery of the Shipper’s Gas has commenced, Gatherer shall send a monthly statement to Shipper indicating the quantity of the Shipper’s Gas delivered (excepting the percentages retained by Gatherer) and the Service Fees due to Gatherer for the services provided during the preceding Accounting Period. [***], Shipper shall remit the invoiced amount on the date that is the later of the 25th Day of the Month following the Accounting Period or fifteen (15) Days after the date of Gatherer’s statement, If Shipper does dispute a portion the invoiced amount, [***]. Shipper shall indemnify and hold Gatherer harmless from any and all charges, penalties, costs and expenses of whatever kind or nature arising from Shipper’s failure to pay undisputed amounts, including costs and expenses of any litigation and reasonable attorneys’ fees associated therewith. Unpaid [***] amounts due shall accrue interest at the lesser of a rate equal to the prime rate in effect at JP Morgan Chase Bank or its successor on the first Day of the month in which delinquency occurs plus [***]% or the maximum permitted by Law.


9.2.	Records; Finality of Statement . Each party agrees to keep records and books of account in accordance with generally accepted accounting principles in the industry. Any statement shall be final as to both parties unless questioned within [*] ([]) [**] after payment thereof has been made.

9.3.

Errors . If following payment of a statement either party asserts an error regarding measurements, billings, payments, or other charge or computation regarding the statement, it shall be adjusted without interest or penalty as soon as reasonably possible, but in any event, within one Month from the date the error is asserted and resolved. Neither party will have any right to recoup or recover prior overpayments or underpayments that result from errors that occur in spite of good faith performance if the amounts involved do not exceed $[***] per Month per CDP. Either party may require prospective correction of such errors. Statements not questioned within [***] ([***]) [***] from the statement date shall be final as to both parties.

9.4.

Records and Charts . Each party shall have the right for [***] ([***]) [***] following receipt of any statement, charge, or computation to examine the books, records, charts, or EFM data of the other party, during normal working hours, to the extent necessary to verify the accuracy of any statement, charge or computation made under the Agreement. The parties shall each preserve all test data, charts, data and other similar records in conformance with Law, but not less than [***] ([***]) [***]. Gatherer shall provide charts and records to Shipper for verifying the accuracy of measurements within [***] ([***]) [***] after request by Shipper. Shipper shall return the charts and records, and any and all copies, within [***] ([***]) [***] after receipt.

10. FORCE MAJEURE

10.1.

Suspension of Obligations . In the event either Gatherer or Shipper is rendered unable, by reason of an event of Force Majeure, as hereinafter defined, to perform, wholly or in part, any obligation or commitment set forth in the Agreement, then upon such party giving notice and full particulars (including all supporting documentation) of such event as soon as practicable after the occurrence thereof, the obligations of both parties shall be suspended to the extent and for the period of such Force Majeure provided that the party claiming an event of Force Majeure shall make all reasonable attempts to remedy the same with all reasonable dispatch.

10.2.

Force Majeure Defined . The term “Force Majeure”, as used herein, means an event that (i) was not within the control of the party claiming its occurrence; and (ii) could not have been prevented by such party through the exercise of due diligence. Events of Force Majeure shall include acts of God, strikes, lockouts or industrial disputes or disturbances, civil disturbances, arrest and restraint of rulers or people, interruptions by government or court orders, necessity for compliance with any present and future valid orders of court, or any law, statute, ordinance or regulation promulgated by any governmental or regulatory authority having proper jurisdiction, acts of the public enemy, wars, riots, blockades, insurrections, including inability to secure materials by reason of allocations promulgated by authorized governmental agencies, epidemics, landslides, lightning, earthquakes, fires, storms, floods, washouts, inclement weather which necessitates extraordinary measures and expense to construct facilities and/or maintain operations, explosions, partial or entire failure of gas supply, breakage or accident to machinery, compressors or lines of pipe, freezing of wells, compressors or pipelines, inability to obtain or delays in obtaining materials, easements or rights-of-way (provided they were pursued with diligence and in a timely manner), inability of downstream markets to take gas or liquids or market failure due to conditions other than price, the shutting in of facilities for the making of repairs, alterations or maintenance to wells, pipelines or plants, or any other cause whether of the kind herein enumerated or otherwise, not reasonably within the control of the party claiming “ Force Majeure ”.


10.3.	Inapplicability of this Article . Neither party shall be entitled to the benefit of the provisions of this Article if the failure was caused by lack of funds, or with respect to the payment of any amount or amounts then due hereunder.

10.4.

Strikes and Lockouts . Settlement of strikes and lockouts shall be entirely within the discretion of the party affected, and the duty that any event of Force Majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes and lockouts by acceding to the demands of the parties directly or indirectly involved in such strikes or lockouts when such course is inadvisable in the discretion of the party having such difficulty.

11. DEFAULT


11.1.	Termination of the Agreement . If either party shall materially fail to perform any of its covenants or obligations under this Agreement, in addition to its other rights and remedies that the non-breaching party may have at law or in equity, the non-breaching party may proceed as follows:

(A)

Notice of Default . The non-defaulting party will provide written Notice to the other party in default, stating specifically the cause for terminating the Agreement, and declaring it to be the intention of the party giving notice to terminate the same; thereupon, the party in default shall have [***] ([***]) [***] Days after receipt of the Notice to remedy or remove or cure the default. If the default is of a nature that requires more than [***] Days to cure, the party in default shall inform the non-defaulting party of the anticipated period (such period not to extend longer than [***] ([***]) [***]) and must diligently begin to cure. If within such period the defaulting party cures the default, then such notice shall be withdrawn and the Agreement shall continue in full force and effect. Failure to cure within the identified period will result in immediate termination of the Agreement. Notwithstanding the foregoing, with respect to a default of Shipper or Gatherer to make payment of undisputed amounts to the other, as applicable, when due, then the period to cure such default shall be [***] ([***]) Days from receipt of Notice thereof.

(B)

Termination . In case the defaulting party does not cure the default within the applicable periods, then the non-defaulting party may immediately terminate this Agreement; provided however, that any termination this Agreement shall not affect or negate any obligations of a party arising or accruing prior to the termination date or otherwise affect any other remedy that the non-breaching party may have at law or in equity.

(C)

Specific Performance . The parties recognize and agree that remedies at law will not be adequate to satisfy a breach of the respective obligations of Producer to sell and Shipper to deliver the Dedicated Gas to the CDPs pursuant to Section 2.1 of this Agreement. Accordingly, the non-breaching party shall be entitled to specific performance in the event of any actual breach by Shipper or Producer of their obligations set forth in Section 2.1 of this Agreement, which remedy shall be exclusive and not in addition to any remedy available by contract, tort, common law or applicable state and federal statutes.


11.2.	Waiver . No waiver by either Shipper or Gatherer of any default of the other under this Agreement shall operate as a waiver of any future default, whether or like or different character or nature, nor shall any failure to exercise any right hereunder be considered as a waiver of such right in the future.

12. MISCELLANEOUS

12.1.

Binding Nature of the Agreement and Assignment . Gatherer shall make no assignment of this Agreement to a non-Affiliate without the express written consent of the Shipper, such consent not to be unreasonably withheld, conditioned, or delayed; provided, however , that no such consent shall be required where the assignee [***]. Nothing herein contained shall in any way prevent Gatherer from pledging or mortgaging all or any part of the Gathering System as security under any mortgage, deed of trust, or other similar lien, or from pledging this Agreement or any benefits accruing hereunder to the party making the pledge, without the assumption of obligations hereunder by the mortgagee, pledgee or other grantee under such an instrument. It is agreed that no sale of all or substantially all of the Gathering Systems nor sale or assignment of any of a Producer’s Acreage shall be made unless the purchaser or assignee thereof shall assume and agree to be bound by this Agreement insofar as the same shall affect and relate to the Acreage, AGS Gathering System or interests so sold or conveyed.


12.2.	No Third Party Beneficiaries . Nothing in this Agreement, expressed or implied, confers any rights or remedies on any person or entity not a party hereto other than successors and assigns, or heirs.

12.3.

Entire Agreement; Amendments . This Agreement and the attached exhibits together with the provisions of those certain Assignments and Assumptions of Cracker Jack Gas Gathering Agreements dated as of May 31, 2013, among the parties described in Recital A, are the entire agreement and understanding between the parties, and supersedes and renders null and void and of no further force and effect any prior understandings, negotiations or agreements between the parties relating to the subject matter hereof, and all amendments and letter agreements in any way relating thereto. No provision of this Agreement may be changed, modified, waived or discharged orally, and no change, modification, waiver or amendment of any provision will be effective except by written instrument to be executed and approved by the parties hereto. No representation, understanding, warranty, condition or agreement of any kind shall be relied upon by the parties except those contained in this Agreement.


12.4.	Headings . The article and section headings are for reference and convenience only and shall not be considered in the interpretation of this Agreement.


12.5.	Governing Law . This Agreement shall be construed in accordance with and governed by the laws of the State of Texas without regard to principles of conflicts of laws. This Agreement has been drafted jointly by the parties. Therefore the rules of contract construction that ambiguities shall be construed against the drafter shall not apply.


12.6.	Counterparts . This Agreement may be executed in one or more original counterparts, all of which, taken together shall constitute an original. This Agreement shall not become effective unless and until it has been executed by both parties.

12.7.

Severability . If any provision of this Agreement is held to be invalid or unenforceable in whole or in part, such provision, only to the extent invalid or unenforceable, shall be severable from this Agreement, and the other provisions of this Agreement shall remain in full force and effect and the remaining provisions hereof shall be liberally construed to carry out the purpose and intent of this Agreement.

12.8.

Non-Disclosure . Unless otherwise agreed to in writing by all the Parties hereto, the terms and conditions of this Agreement shall not be disclosed or revealed to any persons or entities other than those employed by or working on behalf of the parties hereto, except for disclosures: (i) made to a bona fide potential purchaser, investor, partner, lender, financial advisor, consultant or attorney of such party; (ii) required by applicable law, order, decree, regulation, rule (including without limitation, those of any regulatory agency, securities commission or stock exchange) or judicial, administrative, regulatory or self-regulatory proceeding; or (iii) made to owners of a royalty interest in the Acreage whose gas is sold by Shipper, but only for the purpose of determining the cost attributable to such royalty owner’s interest. Notwithstanding the foregoing or anything herein to the contrary, the parties may, without liability hereunder, disclose the existence of this Agreement and the identities of the parties hereto.


12.9.	Limitation of Liability . No party shall be liable to the other party for any indirect, incidental, consequential, special, exemplary, or punitive damages arising from any breach of this Agreement, including, without limitation, any breach of a warranty contained herein or of any obligation to perform services and/or provide deliverables by a specified time.

12.10.

Anti-Corruption and Facilitation Payments . In implementing the requirements of this Agreement, the Parties agree to use reasonable endeavors to comply with, and to use reasonable endeavors to procure that relevant third parties used for fulfilling the Parties’ respective obligations under the Agreement comply with, all laws, rules, regulations, decrees or official governmental orders prohibiting bribery, corruption and money laundering. All financial settlements, billings and reports in connection with the Agreement shall properly reflect the facts related to any activities and transactions handled for the account of the other Party.


12.11.	Further Assurances . Each Party and Producer shall take such acts and execute and deliver such documents as may be reasonably required to effectuate the purposes of this Agreement. Upon termination of this Agreement in accordance with its terms, each Party and Producer shall file any releases with the proper Governmental Authorities as requested by such other Party.

END OF GENERAL TERMS AND CONDITIONS

EXHIBIT C

AGS GATHERING SYSTEM AND DENEX GATHERING SYSTEM

[***]

EXHIBIT D

DEDICATED LEASE SWAP AREA OF MUTUAL INTEREST

[***]

EXHIBIT 21.1

Rice Midstream Partners LP

Subsidiaries



Company		Jurisdiction of Organization
Rice Midstream OpCo LLC		Delaware

Rice Poseidon Midstream LLC		Delaware

Rice Water Services (OH) LLC		Delaware

Rice Water Services (PA) LLC	Delaware

Vantage Energy II Access, LLC	Delaware

Vista Gathering, LLC	Delaware

EXHIBIT 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:


(1)	Registration Statement (Form S-3 No. 333-209089) of Rice Midstream Partners LP,


(2)	Registration Statement (Form S-3 No. 333-214313) of Rice Midstream Partners LP, and


(3)	Registration Statement (Form S-8 No. 333-201169) pertaining to the 2014 Long Term Incentive Plan of Rice Midstream Partners LP;

of our reports dated February 15, 2018, with respect to the consolidated financial statements of Rice Midstream Partners LP and the effectiveness of internal control over financial reporting of Rice Midstream Partners LP included in this Annual Report (Form 10-K) of Rice Midstream Partners LP for the year ended December 31, 2017.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

February 15, 2018

EXHIBIT 31.1

CERTIFICATION

I, Steven T. Schlotterbeck, certify that:


1.	I have reviewed this Annual Report on Form 10-K of Rice Midstream Partners LP;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d.	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Rice Midstream Partners LP

/s/ Steven T. Schlotterbeck

Steven T. Schlotterbeck

President and Chief Executive Officer

Rice Midstream Management LLC, the registrant's General Partner

Date: February 15, 2018

EXHIBIT 31.2

CERTIFICATION

I, Robert J. McNally, certify that:


1.	I have reviewed this Annual Report on Form 10-K of Rice Midstream Partners LP;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c.	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d.	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Rice Midstream Partners LP

/s/ Robert J. McNally

Robert J. McNally

Senior Vice President and Chief Financial Officer

Rice Midstream Management LLC, the registrant's General Partner

Date: February 15, 2018

EXHIBIT 32

CERTIFICATION

In connection with the Annual Report of Rice Midstream Partners LP ("RMP”), on Form 10-K for the period ended December 31, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned certify pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:


(1)	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of RMP.



/s/ Steven T. Schlotterbeck		February 15, 2018
Steven T. Schlotterbeck
President and Chief Executive Officer, Rice Midstream Management LLC, RMP’s General Partner



/s/ Robert J. McNally		February 15, 2018
Robert J. McNally
Senior Vice President and Chief Financial Officer, Rice Midstream Management LLC, RMP’s General Partner

EXHIBIT 99

NON-GAAP FINANCIAL INFORMATION

The EQT Executive STIP for the 2017 plan year and the 2017 Value Driver Performance Share Unit Program utilized EQT’s adjusted EBITDA compared to the EQT’s business plan as a performance measure.

Adjusted 2017 EQT EBITDA was defined as earnings before interest, taxes, depreciation and amortization (i) calculated using a constant commodity price of $2.69 per Mcfe, adjusted for all cash settled derivatives and all basis and fixed price sales set forth in EQT’s 2017 business plan, (ii) excluding the effects of non-cash derivative gains (losses) not included in EQT’s 2017 business plan, (iii) excluding gains/losses on derivatives not designated as hedges, (iv) excluding the effects of non-cash developed and undeveloped oil and gas property and midstream asset impairments, (v) excluding the effects of acquisitions and dispositions of greater than $100 million, and (vi) excluding any charge and benefit associated with the repurchase of debt by EQT (adjusted 2017 EQT EBITDA).

Adjusted EBITDA is a non-GAAP supplemental financial measure that EQT’s management uses to assess: (i) EQT’s performance versus prior periods; (ii) EQT’s operating performance as compared to other companies in its industry; (iii) the ability of EQT’s assets to generate sufficient cash flow to make distributions to its investors; (iv) EQT’s ability to incur and service debt and fund capital expenditures; and (v) the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities. Adjusted EBITDA contains certain adjustments that are not included in EQT’s calculation of EBITDA, a separate non-GAAP supplemental financial measure used by external users of EQT’s financial statements, such as industry analysts, investors, lenders and ratings agencies.

Adjusted EBITDA should not be considered as an alternative to net income, operating income, or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA has important limitations as an analytical tool because it excludes some, but not all, items that affect net income. Additionally, because adjusted EBITDA may be defined differently by other companies in its industry, EQT’s definition of adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Adjusted EBITDA was selected as a performance measure under the EQT Executive STIP for the 2017 plan year and the 2017 Value Driver Performance Share Unit Program because adjusted EBITDA growth drives behavior consistent with the shareholders’ interests, and EQT’s business plan embodies the goals and priorities of EQT. The table below reconciles the EQT’s adjusted EBITDA as shown in this Form 10-K with EQT’s net income, the most comparable financial measure calculated in accordance with GAAP, as set forth in EQT’s annual report on Form 10-K.



(in millions)
Net (loss) income	$	1,858,143
(Deduct)/add back:
Income taxes	(1,115,619		)
Interest expense	202,772
Depreciation, depletion and amortization(*)	1,088,505
EBITDA	2,033,801
Price adjustment	(230,196		)
Impairments	68,183
Acquisitions/divestitures	12,641
Adjusted EBITDA	$	1,537,268