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EX-32.2 - EXHIBIT 32.2 - Rice Midstream Partners LPa322gl.htm
EX-32.1 - EXHIBIT 32.1 - Rice Midstream Partners LPa321djr.htm
EX-31.2 - EXHIBIT 31.2 - Rice Midstream Partners LPa312gl.htm
EX-31.1 - EXHIBIT 31.1 - Rice Midstream Partners LPa311djr.htm
EX-23.1 - EXHIBIT 23.1 - Rice Midstream Partners LPa231rmpconsent.htm
EX-21.1 - EXHIBIT 21.1 - Rice Midstream Partners LPa211significantsubs.htm
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, 2016
or
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
For the transition period from_______ to_______              
Commission File Number: 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.)
2200 Rice Drive
Canonsburg, Pennsylvania
 
15317
(Address of principal executive offices)
 
(Zip code)
 
 
 
Registrant’s telephone number, including area code: (724) 271-7200

 
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. þYes ¨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 þNo
 
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. þYes ¨No
 
 
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þYes ¨No
 
 
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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, or a small reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ
 
Accelerated filer ¨
Non-accelerated filer ¨
 
Smaller reporting company ¨
(Do not check if a smaller reporting company)
 
 
 
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨Yes þNo
 
 
 
The aggregate market value of the common units held by non-affiliates of the registrant as of June 30, 2016: $1,119.3 million
At February 27, 2017, there were 102,272,756 units (consisting of 73,519,133 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
 
 
PART I
 
 
PART II
 
 
PART III
 
 
PART IV


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Cautionary Statement Regarding Forward-Looking Statements
This Annual Report on Form 10-K (the “Annual Report”) contains “forward-looking statements.” All statements, other than statements of historical fact included in this Annual Report, regarding our strategy, future operations, financial position, estimated revenues and income/losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report, the words “could,” “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” included in this Annual Report.
Forward-looking statements may include statements about:
the ability of Rice Energy or our other customers to meet their drilling and development plans on a timely basis or at all;
our business strategy;
realized natural gas, natural gas liquids (“NGLs”) and oil prices;
competition and government regulations;
actions taken by third-party producers, operators, processors and transporters;
pending legal or environmental matters;
costs of conducting our gathering and compression and water services operations;
general economic conditions;
credit and capital markets;
operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;
uncertainty regarding our future operating results; and
plans, objectives, expectations and intentions contained in this Annual Report that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to our gathering and compression and water services businesses. These risks include, but are not limited to, commodity price volatility; inflation; environmental risks; regulatory changes; the uncertainty inherent in projecting future throughput volumes, cash flow and access to capital; the timing of development expenditures of Rice Energy or our other customers; and the other risks described under “Item 1A. Risk Factors” in this Annual Report.
Should one or more of the risks or uncertainties described in this Annual Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.
All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report.


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Commonly Used Defined Terms
As used in the Annual Report, unless the context indicates or otherwise requires, the following terms have the following meanings:
“Rice Midstream Partners LP,” “the Partnership,” “we,” “our,” “us” or like terms refers to Rice Midstream Partners LP and its consolidated subsidiaries, and for periods prior to our initial public offering on December 22, 2014, refers to our Predecessor;
“Predecessor” when discussing periods:
prior to January 29, 2014, refers to the natural gas gathering, compression and water distribution assets and operations of Rice Poseidon;
subsequent to January 29, 2014 through April 17, 2014, refers collectively to the natural gas gathering, compression and water distribution assets and operations of Rice Poseidon taken together with the Alpha Assets; and
subsequent to April 17, 2014 up to December 22, 2014, refers collectively to the natural gas gathering, compression and water distribution assets and operations of Rice Poseidon, the Alpha Assets and the Momentum Assets from their respective dates of acquisition.
“Alpha Assets” refers to the natural gas gathering and water distribution assets owned by Rice Energy’s Marcellus joint venture prior to the completion of Rice Energy’s initial public offering on January 29, 2014. Rice Energy purchased its joint venture partner’s remaining 50% interest in its Marcellus joint venture in connection with the completion of the Rice Energy initial public offering;
“Marcellus joint venture” refers collectively to Alpha Shale Resources, LP and its general partner, Alpha Shale Holdings, LLC;
“Momentum Assets” refers to North System, which is comprised of certain natural gas gathering and compression assets, rights-of-way and associated permits acquired by Rice Poseidon from a third party on April 17, 2014;
“our general partner” or “Midstream Management” refer to Rice Midstream Management LLC, a subsidiary of Rice Energy;
“Rice Energy” refers to Rice Energy Inc. and its consolidated subsidiaries (NYSE: RICE), and for periods prior to Rice Energy’s initial public offering on January 29, 2014, refers to Rice Energy’s predecessor, Rice Drilling B LLC, and its consolidated subsidiaries;
“Rice Midstream Holdings” refers to Rice Midstream Holdings LLC, the owner of our general partner and a subsidiary of Rice Energy;
“GP Holdings” refers to Rice Midstream GP Holdings LP, a subsidiary of Rice Energy;
“Rice Poseidon” refers to Rice Poseidon Midstream LLC, a wholly-owned subsidiary of Rice Midstream Partners LP;
“PA Water” refers to Rice Water Services (PA) LLC, a wholly-owned subsidiary of Rice Midstream Partners LP;
“OH Water” refers to Rice Water Services (OH) LLC, a wholly-owned subsidiary of Rice Midstream Partners LP;
“Vantage” refers collectively to Vantage Energy, LLC and Vantage Energy II, LLC;
“Vantage Midstream Entities” refers collectively to Vantage Energy II Access, LLC and Vista Gathering, LLC; and
“Vantage Midstream Asset Acquisition” refers to the Partnership’s acquisition from Rice Energy of the Vantage Midstream Entities.

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PART I
Item 1. Business
Overview
We are a fee-based, 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 and compression assets consist of natural gas gathering and compression systems that service high quality 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 Rice Energy and third parties in Washington and Greene Counties, Pennsylvania and Belmont County, Ohio. We provide our services under long-term, fee-based contracts, primarily to Rice Energy.
Gas Gathering and Compression
We have secured dedications from Rice Energy under a 15 year, fixed-fee contract for gathering and compression services covering (i) approximately 186,000 gross acres of its acreage position as of December 31, 2016 in Washington and Greene Counties, Pennsylvania, and (ii) any future acreage it acquires within these counties, other than in a select area subject to a pre-existing third-party dedication and subject to the terms of our gas gathering and compression agreement with Rice Energy. In addition, we have secured dedications from third-party customers under fixed-fee contracts for gathering and compression services in Washington County, Pennsylvania, with respect to approximately 29,000 of their existing gross acres, and any future acreage they may acquire within areas of mutual interest of approximately 66,000 gross acres. We refer to these areas of dedication and areas of mutual interest as our “dedicated areas.” Our third-party fixed-fee contracts have a weighted average remaining term of 10 years. For a discussion of the key terms of the fixed-fee contracts, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Operations.”
As of December 31, 2016, our gathering and compression assets consisted of a 4.1 MMDth/d 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.
Rice Energy is our largest customer, and for the year ended December 31, 2016, Rice Energy represented approximately 73% of our gathering volumes. We derive revenues under our long-term contracts by charging customers fixed fees for gathering and compression services based on throughput.
Water Services
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 Rice Energy and third parties in Washington and Greene Counties, Pennsylvania, and Belmont County, Ohio. We have the exclusive right to provide certain fluid handling services to Rice Energy 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 Rice Energy within 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, 2016, our Pennsylvania assets provided access to 22.5 MMgal/d of fresh water from the Monongahela River and several other regional water sources, and 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 Rice Energy and third parties. Rice Energy is our largest customer, and for the year ended December 31, 2016, Rice Energy represented approximately 95% of our water services revenues.
Significant Accomplishments in 2016
Achieved significant growth in average daily throughput to 983 MDth/d, a 52% increase
Increased water services segment delivery volumes from 777 MMgal in 2015 to 1,253 MMgal in 2016, a 61% increase
Completed an underwritten public offering of an aggregate of 9,200,000 common units for net proceeds of approximately $164.1 million in June 2016

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Entered into an equity distribution agreement that established an at-the-market common unit offering program (the “ATM program”) and issued and sold 944,700 common units at an average price per unit of $17.21
Issued 20,930,233 common units in a private placement in October 2016 resulting in net proceeds of approximately $441.0 million
Completed $600.0 million acquisition of midstream assets and acreage dedication covering 85,000 core dry gas Marcellus acres in Greene County, Pennsylvania in October 2016
Our Assets
For the three months ended December 31, 2016, our average daily throughput was 1,203 MDth/d. As of December 31, 2016, our gathering and compression assets consisted of 159 miles of pipeline with gathering capacity of 4,137 MDth/d and compression capacity of 59,500 horsepower. As of December 31, 2016, our Pennsylvania and Ohio water services system capacity was 22.5 MMgal/d and 14.0 MMgal/d, respectively.
2017 Capital Budget
In 2017, we plan to invest $315.0 million, of which $255.0 million will be used for our continued build-out of our Pennsylvania gathering and compression systems and $60.0 million will be used for our water services operations.
For additional information on operations by segment including, but not limited to, revenues, operating income and total assets, please see “Item 8. Financial Statements—Notes to Consolidated Financial Statements—10. Financial Information by Business Segment” of this Annual Report.
Our Customers
One of our principal strengths is having Rice Energy as our anchor customer. During the year ended December 31, 2016, Rice Energy represented approximately 67% of our gathering revenues and 95% of our water service revenues. Rice Energy has dedicated to us all of its natural gas production in the dry gas core of the Marcellus Shale in Washington and Greene Counties, Pennsylvania, excluding amounts subject to a pre-existing third-party dedication.
In addition to the growth we anticipate as a result of Rice Energy’s developmental drilling, we expect to benefit from dedications we have secured from third parties. For the year ended December 31, 2016, third parties represented approximately 27% of our gathering volumes. We have secured dedications under fixed-fee contracts with a weighted average remaining term of 10 years for gathering and compression services in the dry gas core of the Marcellus Shale in southwestern Pennsylvania with respect to current third-party acreage positions of approximately 29,000 gross acres, and any future acreage acquired by such third-parties within areas of mutual interest of approximately 66,000 acres. Furthermore, we believe we will be able to attract additional third-party customers given our assets’ strategic location, available gathering capacity and access to multiple takeaway pipelines. For the year ended December 31, 2016, a single third-party customer represented approximately 33% of our gathering revenues.
Our Relationship with Rice Energy
Rice Energy is one of the largest producers of natural gas in the Appalachian Basin, where it produced 297.7 Bcfe during 2016, an increase of 48% as compared to 2015. As of December 31, 2016, Rice Energy’s drilling inventory consisted of 370 gross (282 net) producing Appalachian wells (242 of which were located on acreage dedicated to us) for gathering and compression services, which provides us with significant opportunities for growth as Rice Energy’s active drilling program continues and its production increases. Rice Energy relies substantially on us to deliver the midstream infrastructure necessary to accommodate its continuing production growth.
In addition to being a high-quality anchor customer, we believe that our relationship with Rice Energy will provide us with competitive advantages to position us to become a leading midstream energy company in the Appalachian Basin. Because Rice Energy Operating LLC, a subsidiary of Rice Energy (“Rice Energy Operating”), owns a 91.75% membership interest in GP Holdings, all of our incentive distribution rights, and a 28% limited partner interest in us, Rice Energy is positioned to indirectly benefit from the growth of our business through organic initiatives or acquisitions, including our acquisitions of its retained midstream assets. In particular, we have a right of first offer on all of Rice Energy’s interests in its gas gathering system in the core of the Utica Shale in Belmont and Monroe Counties, Ohio. The gathering system consists of an aggregate of 92 miles of high-pressure gas gathering pipeline with capacity of 4.8 MMDth/d in the core of the Utica Shale in Belmont and Monroe Counties, Ohio. Average daily throughput on Rice Energy’s Ohio gathering system for the three months ended December 31, 2016 was 904 MDth/d. Rice Olympus Midstream LLC’s system services approximately 45,000 and 20,000 net

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acres of the current positions of Rice Energy and Gulfport Energy Corporation (“Gulfport”), respectively, in Belmont County, Ohio.
On February 1, 2016, Strike Force Holdings, Rice Energy’s wholly-owned subsidiary, and Gulfport Midstream Holdings, LLC, a wholly-owned subsidiary of Gulfport, entered into an Amended and Restated Limited Liability Company Agreement of Strike Force Midstream to engage in the natural gas midstream business in approximately 319,000 acres in Belmont and Monroe Counties, Ohio. Strike Force Holdings owns a 75% membership interest in Strike Force Midstream. The Strike Force Midstream LLC (“Strike Force Midstream”) system currently services an aggregate of approximately 98,000 acres of Gulfport’s and Consol Energy Inc.’s current positions.
While we believe that we are well positioned to be the ultimate acquirer of these retained midstream assets from Rice Energy, including those subject to our right of first offer, Rice Energy is under no obligation to contribute these assets to us. Furthermore, our relationship with Rice Energy poses potential conflicts of interest in connection with any such acquisition. Any decision to exercise our right of first offer will require the approval of the board of directors of our general partner, all of the members of which are appointed by Rice Energy as the indirect owner of our general partner. For more information regarding our relationship with Rice Energy, please read “Item 13. Certain Relationships and Related Transactions, and Director Independence Procedures for Review, Approval and Ratification of Related Person Transactions.”
Rice Energy’s Existing Third-Party Commitments
Certain of Rice Energy’s acreage is subject to pre-existing third-party dedications. Rice Energy has entered into contracts with MarkWest Energy Partners LP (“MarkWest”), pursuant to which MarkWest will construct gas gathering facilities to gather Rice Energy’s Utica Shale production from certain dedicated areas in Ohio, including portions of Belmont County, from which Rice Energy will produce wet gas requiring processing.
Title to Properties and Rights-of-Way
Our real property is classified into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental 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 or Rice Energy 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
As a result of our relationship with Rice Energy, we do not compete for the portion of Rice Energy’s existing operations for which we currently provide midstream services and will not compete for future portions of Rice Energy’s operations within our dedicated areas. However, we will face competition in attracting third-party volumes to our gathering and compression systems and third-party customers for our water services business. In addition, these third parties may develop their own gathering and compression systems or water distribution systems in lieu of employing our assets. Our ability to attract such third-party volumes to our gathering and compression systems and third-party customers for our water services business depends on our ability to evaluate and select suitable projects and to consummate transactions in a highly competitive

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environment. Also, there is substantial competition for capital available for investment in the natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. We may not be able to compete successfully in the future in attracting third-party volumes to our gathering and compression systems or third-party customers for our water services business, attracting and retaining quality personnel, and raising additional capital, which could have a material adverse effect on our business.
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 Rice Energy produces, as well as the revenues Rice Energy receives for sales of their 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 Rice Energy’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 Rice Energy produces, as well as the revenues Rice Energy receives for sales of their 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.
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 to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. EPAct 2005 provided FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases FERC’s civil penalty authority under the Natural Gas Policy Act (“NGPA”) from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the transportation and sale of natural gas for resale in interstate commerce. In Order No. 670, the FERC promulgated rules implementing the anti-market manipulation provision of EPAct 2005. The rules make it unlawful: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The 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.

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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 the subject of ongoing 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 gathering facilities 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 (the “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 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. Moreover, the 2011 Pipeline Safety Act also increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day of violation and also from $1.0 million to $2.0 million for a related series of violations. 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

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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 May 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.  More recently in January 2017, PHMSA finalized new regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, repairs and leak detection), regardless of the pipeline’s proximity to an HCA. The final rule also requires all pipelines in or affecting an HCA to be capable of accommodating in-line inspection tools within the next 20 years. In addition, the final rule extends annual and accident reporting requirements to gravity lines and all gathering lines and also imposes inspection requirements on pipelines in areas affected by extreme weather events and natural disasters, such as hurricanes, landslides, floods, earthquakes, or other similar events that are likely to damage infrastructure.
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, the President signed into law new legislation entitled Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 PIPES Act”). The 2016 PIPES 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. The 2016 PIPES Act also requires that PHMSA publish periodic updates on the status of those mandates outstanding from 2011 Pipeline Safety Act, of which approximately half remain to be completed. The mandates yet to be acted upon include requiring certain shut-off valves on transmission lines, mapping all HCAs, and shortening the deadline for accident and incident notifications.
Regulation of Environmental and Occupational Safety and Health Matters
General
Our natural gas gathering, compression 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 may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties and natural resource damages. Certain environmental statutes impose

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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 capital costs to construct, maintain and operate equipment and facilities. While these laws and regulations affect our maintenance 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 believe that the various activities in which we are presently engaged that are subject to environmental laws and regulations are not expected to 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, Rice Energy, 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, and advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and also finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the Bureau of Land Management (“BLM”) finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision has not yet been issued.
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 concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts:  water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits.  Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level.
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 new 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,

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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. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we 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.
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 or delays 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 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.
Site 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 and compression 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 it 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

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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, 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 also 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 (the “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 Corps’ jurisdiction became effective. 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. 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.

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Occupational Safety and Health Act
We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”), as amended. 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, 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 of their potential criteria pollutant emissions must comply with best available control technology (“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 June 2016, the EPA finalized new regulations that set emissions standards and leak detection and repair requirements for methane and volatile organic compounds from new and modified oil and natural gas production and natural gas processing and transmission facilities. 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 and issued information collection requests to oil and gas operators. Additional 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. 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 and proposed rules could result in increased compliance costs on our operations. 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 event 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

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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 financial condition and operations.
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. The officers of our general partner, who are also officers of Rice Energy, manage our operations and activities. As of December 31, 2016, Rice Energy employed approximately 106 people who provide direct support to our operations. All of the employees required to conduct and support our operations are employed by Rice Energy and seconded to us pursuant to a secondment agreement and all of our Rice Energy full-time personnel are subject to our omnibus agreement with Rice Energy (“Omnibus Agreement”).
Facilities
Rice Energy’s corporate headquarters are in Canonsburg, Pennsylvania. Pursuant to the Omnibus Agreement, we reimburse Rice Energy for our proportionate share of Rice Energy’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 and should not be considered part of this report or any other filing we make with the SEC. We make available, free of charge, on our website, the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after filing such reports with the SEC. Other information such as presentations, our Corporate Governance Guidelines, the charter of the Audit Committee and the Code of Business Conduct and Ethics are available on our website and in print to any unitholder who provides a written request to the Corporate Secretary at 2200 Rice Drive, Canonsburg, Pennsylvania 15317. Our Code of Business Conduct and Ethics applies to all directors, officers and employees, including the Chief Executive Officer and Chief Financial Officer.
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.

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Item 1A. Risk Factors
You should carefully consider the following risk factors together with all of the other information included in this Annual Report, including the matters addressed under “Cautionary Statement Regarding Forward-Looking Statements,” in evaluating an investment in our common units. If any of the following risks were to occur, our business, financial condition, results of operations and cash available for distribution could be materially adversely affected.
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 Rice Energy, any development that materially and adversely affects Rice Energy’s operations, financial condition or market reputation could have a material and adverse impact on us.
For the year ended December 31, 2016, Rice Energy accounted for approximately 67% of our gathering revenues and 95% of our water services revenues. We are substantially dependent on Rice Energy as our most significant current customer, and we expect to derive a substantial majority of our revenues from Rice Energy for the foreseeable future. As a result, any event, whether in our dedicated areas or otherwise, that adversely affects Rice Energy’s production, drilling and completion 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 Rice Energy, including, among others:
a reduction in or slowing of its anticipated drilling and production schedule, which would directly and adversely impact demand for our gathering and compression and water services;
the volatility of natural gas prices, which could have a negative effect on the value of its properties, its drilling programs or its ability to finance its operations;
changes in regulations or statutes applicable to us or Rice Energy, which could have a negative effect on the value of our facilities or services or Rice Energy’s properties, its drilling programs or its ability to finance its operations;
the availability of capital on an economic basis to fund its exploration and development activities;
its ability to replace reserves;
its drilling and operating risks, including potential environmental liabilities; and
its access to downstream transportation capacity and any constraints or interruptions thereof.
Further, we are subject to the risk of non-payment or non-performance by Rice Energy, including with respect to our gathering and compression agreement and water services agreements. We cannot predict the extent to which Rice Energy’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 Rice Energy’s ability to execute its drilling and development program or perform under our gathering and compression agreement or our amended and restated water services agreements with Rice Energy (“Water Services Agreements”). Any material non-payment or non-performance by Rice Energy could reduce our ability to make distributions to our unitholders.
Also, due to our relationship with Rice Energy, 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 Rice Energy’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 Rice Energy 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 Rice Energy 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 Rice Energy. While Rice Energy 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 areas 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 Rice Energy could have a material adverse effect on our business, financial condition, results or operations and ability to make quarterly cash distributions to our unitholders.

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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 and compression services and water services;
the market price of natural gas and its effect on Rice Energy’s and third parties’ drilling schedule as well as produced volumes;
Rice Energy’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 Rice Energy) 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 Rice Energy’s ability to replace declining production and our ability to secure new sources of production from Rice Energy or third parties. Additionally, our water services are directly associated with Rice Energy’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 Rice Energy’s production or completions 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 Rice Energy is able to execute its drilling and completion program and achieve its anticipated production targets, the volumes of natural gas we gather should increase. To the extent Rice Energy completes or reduces its activity or otherwise ceases to drill and complete wells, revenues for our gathering and compression and water services will be directly and adversely affected. Our ability to maintain water services revenues is substantially dependent on continued completion activity by Rice Energy or third parties over time, as well as the volumes of produced water. 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 Rice Energy or third

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parties. The primary factors affecting our ability to obtain additional sources of natural gas include (i) the success of Rice Energy’s drilling activity in our areas of operation, (ii) Rice Energy’s acquisition of additional acreage and (iii) 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 Rice Energy or other fresh water distribution customers complete wells with shorter lateral lengths, the demand for our fresh water distribution services would be reduced.
We have no control over Rice Energy’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 Rice Energy 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 other equipment.
Rice Energy could elect to reduce its drilling and completion 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 availability of imported 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, LNG and other commodities. Declines in commodity prices could have a negative impact on Rice Energy’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 Rice Energy’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 to NYMEX Henry Hub prices, also known as basis differentials, result from variances in regional natural gas prices compared to NYMEX Henry Hub prices as a result of regional supply and demand factors. 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 Rice Energy’s production in the future than local pricing.
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 systems, our 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.

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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 and compression 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 plan and cause a decrease in throughput on our gathering systems. Any of the aforementioned throughput decreases could have a material adverse effect on our financial condition and results of operations.
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 Rice Energy’s, our other customers’ or our properties, which could cause subsidence or other damage to Rice Energy’s, our other customers’ or our properties, adversely impact our customers’ drilling or adversely impact our gathering and compression activities. In such event, our or our customers’ operations may be impaired or interrupted, which could have a material adverse effect on our financial condition and results of operations.
Finally, gathering and compression 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 Rice Energy.
Part of our long-term growth strategy includes identifying additional opportunities to offer services to third parties. For the year ended December 31, 2016, Rice Energy accounted for approximately 67% of our gathering revenues and 95% of our water services revenues. Our ability to increase throughput on our gathering and compression systems 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 Rice Energy and the fact that a substantial portion of the capacity of our gathering and compression systems and water services systems will be necessary to service Rice Energy’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 pursuant 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

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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, Rice Energy and its affiliates 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 electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas 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 and ability to make quarterly cash distributions to our unitholders. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas in the markets served by our systems, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.
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 expansion capital expenditures and investment 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 Rice Energy’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, Rice Energy 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.
Our construction or purchase of new gathering and compression 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 cash flows, results of operations and financial condition and, as a result, our ability to distribute cash to our unitholders.
The construction of additions or modifications to our existing systems and the construction or purchase of new assets involves 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 and compression or other assets may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. 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 supplies to our existing gathering pipelines 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

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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, results of operations and financial condition and, as a result, our ability to make cash 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 and ability to make quarterly cash 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 agreement 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.

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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 Rice Energy 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 Rice Energy may be a factor considered in credit evaluations of us. This is because Rice Energy controls our business activities, including our cash distribution policy and growth strategy. Any adverse change in the financial condition of Rice Energy, including the degree of its financial leverage and its dependence on cash flow from us to service its indebtedness, or a downgrade of Rice Energy’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 Rice Energy, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service (“Moody’s”) may consider the leverage and credit profile of Rice Energy 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 Rice Energy or 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 expectation of ongoing divestitures of midstream energy assets by industry participants, including Rice Energy. Though our Omnibus Agreement provides us with a right of first offer with respect to certain of Rice Energy’s gas gathering assets in Belmont County, Ohio that will require Rice Energy to provide us with an opportunity to offer to purchase these assets that it may sell, the consummation and timing of any future transactions pursuant to the exercise of our right of first offer with respect to any particular business opportunity will depend upon, among other things, our ability to negotiate definitive agreements with respect to such opportunities and our ability to obtain financing on acceptable terms. Additionally, Rice Energy is under no obligation to accept any offer made by us with respect to such opportunities. Furthermore, for a variety of reasons, we may decide not to exercise these rights when they become available, and our decision will not be subject to unitholder approval. As such, there is no guarantee that we will be able to make any such offer or consummate any acquisition of midstream assets from Rice Energy. Furthermore, many factors could impair our access to future midstream assets and the willingness of Rice Energy to offer us acquisition opportunities, including a change in control of Rice Energy or a transfer of the incentive distribution rights held by Rice Energy to a third party. A material decrease in divestitures of midstream energy assets from Rice Energy or otherwise would limit our opportunities for future acquisitions and could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders.
If we are unable to make accretive acquisitions from Rice Energy or third parties, whether because, among other reasons, (i) Rice Energy elects not to sell or contribute additional assets to us or to offer acquisition opportunities to us, (ii) we are unable to identify attractive third-party acquisition opportunities, (iii) we are unable to negotiate acceptable purchase contracts with Rice Energy 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

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will be accretive, these acquisitions may nevertheless result in a decrease in the cash available for distribution on a per unit basis.
Any acquisition, including the Vantage Midstream Asset 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, results of operations, financial condition and ability to make quarterly cash 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 Rice Energy, 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 Rice Energy’s or other customers’ well completions, any reduction in produced water attributable to completion activity, or to the extent that Rice Energy 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 Rice Energy to source a portion of the fresh water we distribute. The availability of our and Rice Energy’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 the subject of ongoing 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

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results of operations and cash flows. FERC has civil penalty authority under the NGA and NGPA to impose penalties for current violations of up to $1,000,000 per day for each violation and disgorgement of profits associated with any violation.
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 and compression systems, the number of wells for which we provide water services, which could and adversely impact our revenues.
All of Rice Energy’s natural gas production 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, Rice Energy, 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 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, and advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and also finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision has not yet been issued.
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 concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts:  water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits.  Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level.
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,

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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 Rice Energy 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 “greenhouse gases” 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, 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 of their potential criteria pollutant emissions 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 June 2016, the EPA finalized new regulations that set emissions standards and leak detection and repair requirements for methane and volatile organic compounds from new and modified oil and natural gas production and

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natural gas processing and transmission facilities. 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 and issued information collection requests to oil and gas operators. Additional 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. 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 and proposed rules could result in increased compliance costs on our operations. 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 event 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 financial condition and operations.
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. Effective October 25, 2013, the PHMSA finalized rules that increased the maximum administrative civil penalties for violations of the pipeline safety laws and regulations that occur after January 3, 2012 to $200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations. 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 safely build pipeline infrastructure.
PHMSA has also published final rules in January 2017 for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, repairs and leak detection), regardless of the pipeline’s proximity to an HCA. The final rule also requires all pipelines in or affecting an HCA to be capable of accommodating in-line inspection tools within the next 20 years. In addition, the final rule extends annual and accident reporting requirements to gravity lines and all gathering lines and also imposes inspection requirements on pipelines in areas affected by extreme weather events and natural disasters, such as hurricanes, landslides, floods, earthquakes, or other similar events that are likely to damage infrastructure. PHMSA also proposed rules in March 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

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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, the President signed the 2016 PIPES Act into law. The 2016 PIPES 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. The 2016 PIPES Act also requires that PHMSA publish periodic updates on the status of those mandates outstanding from 2011 Pipeline Safety Act, of which approximately half remain to be completed. The mandates yet to be acted upon include requiring certain shut-off valves on transmission lines, mapping all HCAs, and shortening the deadline for accident and incident notifications. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our cash flow. 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 ability to distribute cash and, accordingly, the market price for our common units.
Our operations are subject to all of the hazards inherent in the gathering and compression of natural gas, including:
damage to pipelines, compressor stations, related equipment and surrounding properties caused by natural disasters, acts of terrorism and acts of third parties;
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;
fires, 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. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

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The loss of key personnel could adversely affect our ability to operate.
We depend on the services of a relatively small group of our general partner’s and Rice Energy’s senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. Because competition for experienced personnel in the midstream industry is intense, we may not be able to find acceptable replacements with comparable skills and experience. The loss of the services of our general partner’s senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.
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 Rice Energy.
We are managed and operated by the board of directors of our general partner. Affiliates of Rice Energy 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 and Rice Energy. If our general partner and the officers and employees of Rice Energy do not devote sufficient attention to the management and operation of our business, our financial results may suffer, and our ability to make distributions to our unitholders may be reduced.
Risks Related to Our Partnership Structure
Our general partner and its affiliates, including Rice Energy, 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.
Rice Energy 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 Rice Energy. 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 Rice Energy. Further, our directors and officers who are also directors and officers of Rice Energy have a fiduciary duty to manage Rice Energy in the best interests of the stockholders of Rice Energy. Conflicts of interest will arise between Rice Energy and any of its affiliates, including 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 Rice Energy 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 Rice Energy to pursue a business strategy that favors us;
Rice Energy, as our anchor customer, has an economic incentive to cause us not to seek higher gathering fees, even if such higher fees would reflect fees that could be obtained in arm’s-length, third-party transactions;
Rice Energy may choose to shift the focus of its investment and operations to areas not serviced by our assets;
actions taken by our general partner may affect the amount of cash available to pay distributions to unitholders or accelerate the right to convert subordinated units;
the directors and officers of Rice Energy have a fiduciary duty to make decisions in the best interests of the stockholders of Rice Energy, which may be contrary to our interests and the interest of our unitholders;
our general partner is allowed to take into account the interests of parties other than us, such as Rice Energy, 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 Rice Energy 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;

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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 which, in turn, may affect the ability of the subordinated units owned by GP Holdings to convert;
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, which may be used to fund distributions on our subordinated units or the 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 may compete with us, and our general partner and its affiliates have limited obligations to present business opportunities to us; 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 Rice Energy 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 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 acquisitions and expansion capital expenditures. 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 acquisitions or expansion capital expenditures, the payment of

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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;
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

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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 our officers, directors and employees. If a dispute were to arise between a limited partner and us or our officers, directors or employees, 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, unitholders have limited voting rights and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by Rice Energy, 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.
Even if holders of our common units are dissatisfied, they cannot currently remove our general partner without its consent.
Unitholders are currently unable to remove our general partner without its consent because our general partner and its affiliates, including Rice Energy, own sufficient units to be able to prevent its removal. Our general partner may not be removed except for cause by vote of the holders of at least 66 2/3% of all outstanding common and subordinated units, including any units owned by our general partner and its affiliates, voting together as a single class. As of December 31, 2016, Rice Energy Operating indirectly owned 26% of our outstanding common and subordinated units. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner.

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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.
GP Holdings 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.
GP Holdings has the right, as the holder of our incentive distribution rights, at any time when there are no subordinated units outstanding and 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 GP Holdings 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 GP Holdings will equal the number of common units that would have entitled GP Holdings 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 GP Holdings 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 GP Holdings 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. GP Holdings 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 Rice Energy may be transferred to a third party without unitholder consent.
GP Holdings may transfer our incentive distribution rights to a third party at any time without the consent of our unitholders. If GP Holdings 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

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distribution rights by our general partner could reduce the likelihood of GP Holdings selling or contributing additional midstream assets to us, as GP Holdings 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 Rice Energy), 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 a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
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.
GP Holdings may sell 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 27, 2017, GP Holdings held 3,623 common units and all 28,753,623 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. Additionally, we have agreed to provide GP Holdings with certain registration rights, pursuant to which we may be required to register common units they hold 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 Rice Energy) 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

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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. Our general partner and its affiliates (including Rice Energy) own an aggregate of less than 1% of our common and 100% of our subordinated units. At the end of the subordination period, assuming no additional issuances of units (other than upon the conversion of the subordinated units), our general partner and its affiliates will own 28% of our 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. 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 Rice Energy;
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.

34


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, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we incur additional costs associated with our SEC reporting requirements.
We also incur significant expense in order to maintain director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on our board or as executive officers.
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 Internal Revenue Service 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. Distributions to our unitholders would generally be taxed again as corporate distributions, 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

35


traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.
In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code (the “Final Regulations”) were published in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final Regulations affect our ability to be treated as a partnership for U.S. federal income tax purposes.
However, 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 certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any similar or future legislative changes could negatively impact the value of an investment in 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. Recently enacted legislation alters the procedures for assessing and collecting taxes due for taxable years beginning after December 31, 2017, in a manner that might substantially 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 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 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.
Further, pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Under our limited partnership agreement, our general partner is permitted to make elections under the new rules to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced.
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. If our unitholders are a tax-exempt entity or a non-U.S. person, they should consult their tax advisor before investing in our common units.

36


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. Our counsel is unable to opine as to the validity of this approach. 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 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.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. As of December 31, 2016, Rice Energy indirectly held significant interests in our capital and profits. Therefore, a transfer by Rice Energy Operating of all or a portion of its interests in us could, in conjunction with the trading of common units held by the public, result in a termination of our partnership for federal income tax purposes. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once.

37


Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one calendar year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in taxable income for the unitholder’s taxable year that includes our termination. Our termination would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for U.S. federal income tax purposes following the termination. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS recently announced a relief procedure whereby if a publicly-traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the two short tax periods included in the year in which the termination occurs.
Pursuant to an agreement between the Partnership and the IRS regarding our 2016 tax reporting, we will have 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 will result 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 expects to provide a single Schedule K-1 to each unitholder reflecting the unitholder’s taxable income for the full calendar year.
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. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.
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
We are party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe that all such matters involve amounts which, if resolved unfavorably, either individually or in the aggregate, will not have a material adverse effect on our financial condition, results of operations or cash flows. When we determine that a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at the time. We disclose contingencies where an adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed.
In 2016, we reached a settlement with the PADEP related to civil penalties for certain Notices of Violations (“NOVs”) received from December 2011 through April 2016 under the Clean Streams Law, the 2012 Oil and Gas Act, the Solid Waste Management Act, and the Dam Safety and Encroachments Act and have paid fines to settle such NOVs with the PADEP for $207,000.
Item 4. Mine Safety Disclosures
Not applicable.

38


PART II

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
Market Information. Our common units are listed on the NYSE under the symbol “RMP.” The high and low sales prices reflected on the NYSE per unit for 2016 and 2015 are summarized below:
 
 
2016
 
2015
(in dollars per share)
 
High
 
Low
 
Distributions paid per Common Unit
 
High
 
Low
 
Distributions paid per Common Unit
1st Quarter
 
$
15.39

 
$
8.40

 
$
0.1965

 
$
17.19

 
$
12.91

 
$
0.0204

2nd Quarter
 
$
20.65

 
$
14.21

 
$
0.2100

 
$
18.17

 
$
14.21

 
$
0.1875

3rd Quarter
 
$
24.30

 
$
18.05

 
$
0.2235

 
$
17.65

 
$
11.07

 
$
0.1905

4th Quarter
 
$
24.88

 
$
20.05

 
$
0.2370

 
$
16.44

 
$
10.63

 
$
0.1935

On February 27, 2017, the last sales price of our common units, as reported on the NYSE, was $24.11 per common unit.
On January 20, 2017, the Board of Directors of our general partner declared a cash distribution to our unitholders of $0.2505 per common and subordinated unit for the fourth quarter of 2016. The cash distribution was paid on February 16, 2017, to unitholders of record at the close of business on February 7, 2017. Also on February 16, 2017, a cash distribution of $0.9 million was 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.
Holders. The number of unitholders of record of our common units was approximately 65 as of February 27, 2017. 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 held in “street name” are not.
We have also issued 28,753,623 subordinated units for which there is no established public trading market. All of the subordinated units are held by GP Holdings. GP Holdings receives quarterly distributions on these units only after sufficient distributions have been paid to the common units.
Certain Information from our Partnership Agreement. Set forth below is a summary of certain provisions of our partnership agreement that relate to cash distributions and incentive distribution rights.
Our Cash Distribution Policy. Within 60 days after the end of each quarter, it is our intent to distribute to the holders of common and subordinated units on a quarterly basis the minimum quarterly distribution of $0.1875 per unit (or $0.75 on an annualized basis) to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates.
Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy. There is no guarantee that we will make cash distributions to our unitholders. We do not have a legal or contractual obligation to pay distributions quarterly or on any other basis or at our minimum quarterly distribution rate or at any other rate. Our cash distribution policy is subject to certain restrictions and may be changed at any time.
The reasons for such uncertainties in our stated cash distribution policy include the following factors:
Our cash distribution policy is subject to restrictions on cash distributions under our revolving credit facility, which contains financial tests and covenants that we must satisfy. Should we be unable to satisfy these restrictions or if we are otherwise in default under our revolving credit facility, we will be prohibited from making cash distributions to our unitholders notwithstanding our stated cash distribution policy.
Our general partner has the authority to establish cash reserves for the prudent conduct of our business, including for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish.
Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates (including Rice Energy) for all direct and indirect expenses they incur on our behalf. Our partnership

39


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 obligations to reimburse our general partner and its affiliates are governed by our partnership agreement and the Omnibus Agreement. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available to pay distributions to our unitholders.
Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner.
Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.
We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors detailed in this prospectus as well as increases in our operating or general and administrative expenses, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our cash available for distribution to common unitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase.
If we make distributions out of capital surplus, as opposed to operating surplus, any such distributions would constitute a return of capital and would result in a reduction in the minimum quarterly distribution and the target distribution levels. We do not anticipate that we will make any distributions from capital surplus.
If and to the extent our cash available for distribution materially declines, we may elect to reduce our quarterly cash distributions in order to service or repay our debt or fund expansion capital expenditures.
General Partner Interest. Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner may in the future own common units or other equity interests in us and will be entitled to receive distributions on any such interests.
Subordinated Units. GP Holdings owns all of our subordinated units. The principal difference between our common units and subordinated units is that, for any quarter during the “subordination period,” holders of the subordinated units will not be entitled to receive any distribution from operating surplus until the common units have received the minimum quarterly distribution for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.
When the subordination period ends, each outstanding subordinated unit will convert into one common unit, which will then participate pro-rata with the other common units in distributions.
Incentive Distribution Rights. All of the incentive distribution rights are held by 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.

40


For any quarter in which we have distributed cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum distribution and distributed cash from surplus to the outstanding common units to eliminate any cumulative arrearages in payment of the minimum quarterly distribution, then we will distribute any additional 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%
Securities Authorized for Issuance under Equity Compensation Plans. See “Item 12. Security Ownership of Certain Beneficial Owners and Management” for information regarding our equity compensation plans as of December 31, 2016.
Issuer Purchases of Equity Securities. The following table contains information about the acquisition of our common units for the year ended December 31, 2016.
Period
 
Total Number of Units Withheld (1)
 
Average Price Paid per Unit
 
Total Number of Units Purchased as Part of Publicly Announced Plans or Programs
 
Maximum Number (or Approximate Dollar Value) of Units that May Be Purchased Under the Plans or Programs
January 1 - January 31, 2016
 

 
$

 

 

February 1 - February 28, 2016
 

 

 

 

March 1 - March 31, 2016
 

 

 

 

April 1 - April 30, 2016
 

 

 

 

May 1 - May 31, 2016
 

 

 

 

June 1 - June 30, 2016
 
59,031

 
18.94

 

 

July 1 - July 31, 2016
 

 

 

 

August 1, August 31, 2016
 

 

 

 

September 1 - September 30, 2016
 

 

 

 

October 1 - October 31, 2016
 

 

 

 

November 1 - November 30, 2016
 

 

 

 

December 1 - December 31, 2016
 
59,676

 
23.47

 

 

    Total
 
118,707

 
$
21.22

 

 

(1)
All units withheld during 2016 were used to offset tax withholding obligations that occur upon the vesting of phantom units and delivery of common stock under the terms of our long-term incentive plan.


41


Item 6. Selected Financial Data
Set forth below is our selected historical consolidated financial data as of and for the years ended December 31, 2016, 2015, 2014, 2013 and 2012. The selected historical consolidated financial data set forth below is not intended to replace our historical consolidated financial statements. You should read the following data along 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 report. We believe that the assumptions underlying the preparation of our historical consolidated financial statements are reasonable.
 
 
Year Ended December 31,
(in thousands, except unit data)
 
2016
 
2015
 
2014
 
2013
 
2012
Statement of operations data:
 
 
 
 
 
 
 
 
 
 
Total operating revenues
 
$
201,623

 
$
114,459

 
$
6,448

 
$
498

 
$

Total operating expenses
 
74,681


52,423


37,015

 
5,706

 
2,780

Operating income (loss)
 
126,942


62,036

 
(30,567
)
 
(5,208
)
 
(2,780
)
Net income (loss)
 
121,610


52,495

 
(31,328
)
 
(9,012
)
 
(3,128
)
Limited partner net income
 
120,182

 
45,199

 
1,162

 
 
 
 
Net income attributable to RMP per limited partner unit (basic and diluted) (1)
 
 
 
 
 
 
 
 
 
 
Common units (basic)
 
$
1.46

 
$
0.76

 
$
0.02

 
 
 
 
Common units (diluted)
 
$
1.45

 
$
0.76

 
$
0.02

 
 
 
 
Subordinated units
 
$
1.50

 
$
0.76

 
$
0.02

 
 
 
 
Balance sheet data (at period end):
 
 
 
 
 
 
 
 
 
 
Cash
 
$
21,834

 
$
7,597

 
$
26,834

 
$
148

 
$

Total property and equipment, net
 
805,027

 
578,026

 
323,871

 
74,058

 
30,283

Total assets
 
1,399,217

 
689,790

 
443,091

 
74,445

 
30,283

Total long-term debt
 
190,000

 
143,000

 

 

 

Total partners’ capital/parent net equity
 
1,182,406

 
511,834

 
429,944

 
66,622

 
24,056

Net cash provided by (used in):
 
 
 
 
 
 
 
 
 
 
Operating activities
 
$
154,117

 
$
70,006

 
$
(25,021
)
 
$
(7,186
)
 
$
(2,197
)
Investing activities
 
(721,087
)
 
(379,991
)
 
(336,273
)
 
(44,244
)
 
(14,705
)
Financing activities
 
581,207

 
290,748

 
387,980

 
51,578

 
16,902

Operating data:
 
 
 
 
 
 
 
 
 
 
Gathering volumes (MDth/d)
 
 
 
 
 
 
 
 
 
 
Affiliate
 
714

 
547

 
345

 
95

 
32

Third-party
 
269

 
100

 
33

 

 

Compression volumes (MDth/d)
 
 
 
 
 
 
 
 
 
 
Affiliate
 
327

 
33

 

 

 

Third-party
 
245

 
31

 

 

 

Water services volumes (MMgal)
 
 
 
 
 
 
 
 
 
 
Affiliate
 
1,121

 
600

 

 

 

Third-party
 
132

 
177

 

 

 

Other financial data (unaudited):
 
 
 
 
 
 
 
 
 
 
Adjusted EBITDA (2)
 
$
158,353

 
$
63,780

 
$
(9,541
)
 
$
(4,018
)
 
$
(1,997
)
(1)
Net income per limited partner unit is presented only for the periods subsequent to our IPO and does not include results attributable to the Water Assets (defined herein) prior to their acquisition as these results are not attributable to limited partners of the Partnership.
(2)
Please read “—Non-GAAP Financial Measures.”

42


Non-GAAP Financial Measures
Adjusted EBITDA is a supplemental non-GAAP measure that is used by management and external users of our consolidated financial statements, such as securities analysts, investors and lenders. We define Adjusted EBITDA as net income (loss) before interest expense, income tax (benefit) expense, depreciation expense, amortization of intangible assets, non-cash equity compensation expense, amortization of deferred financing costs and certain other non-recurring items management believes affect the comparability of our operating results.
Adjusted EBITDA is a non-GAAP supplemental financial measure 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 the presentation of Adjusted EBITDA will provide useful information to investors in assessing our financial condition and results of operations. The measures of the accounting principles generally accepted in the United States (“GAAP”) most directly comparable to Adjusted EBITDA are net income and net cash provided by (used in) operating activities. Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to GAAP net income or net cash provided by (used in) operating activities. Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income and net cash provided by (used in) operating activities. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA may be defined differently by other companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

43


The following table presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measures of net income (loss) and cash used in operating activities.
 
 
Year ended December 31,
(in thousands)
 
2016
 
2015
 
2014
 
2013
 
2012
Adjusted EBITDA reconciliation to Net income (loss):
 
 
 
 
 
 
 
 
 
 
Net income (loss)
 
$
121,610

 
$
52,495

 
$
(31,328
)
 
$
(9,012
)
 
$
(3,128
)
     Interest expense
 
3,931

 
3,164

 
13,571

 
3,804

 
348

     Income tax expense (benefit)
 

 
5,812

 
(12,920
)
 

 

     Depreciation expense
 
25,170

 
16,399

 
4,165

 
1,190

 
783

     Acquisition costs
 
125

 

 
1,519

 

 

     Amortization of intangible assets
 
1,634

 
1,632

 
1,156

 

 

     Non-cash equity compensation expense
 
2,873

 
4,501

 
816

 

 

     Incentive unit expense
 

 
1,044

 
13,480

 

 

     Amortization of deferred financing costs
 
1,479

 
576

 

 

 

     Other expense
 
1,531

 
543

 

 

 

Adjusted EBITDA attributable to Water Assets prior to acquisition (1)
 

 
(22,386
)
 

 

 

Adjusted EBITDA
 
$
158,353

 
$
63,780

 
$
(9,541
)
 
$
(4,018
)
 
$
(1,997
)
 
 
 
 
 
 
 
 
 
 
 
Reconciliation of Adjusted EBITDA to Cash provided by (used in) operating activities:
 
 
 
 
 
 
Adjusted EBITDA
 
$
158,353

 
$
63,780

 
$
(9,541
)
 
$
(4,018
)
 
$
(1,997
)
     Interest expense
 
(3,931
)
 
(3,164
)
 
(13,571
)
 
(3,804
)
 
(348
)
     Acquisition costs
 
(125
)
 

 
(1,519
)
 

 

     Other expense
 
(1,531
)

(543
)
 

 

 

Changes in operating assets and liabilities which provided (used) cash
 
1,350

 
(12,453
)
 
(390
)
 
636

 
148

Adjusted EBITDA attributable to Water Assets prior to acquisition (1)
 

 
22,386

 

 

 

Net cash provided by (used in) operating activities
 
$
154,116

 
$
70,006

 
$
(25,021
)
 
$
(7,186
)
 
$
(2,197
)

(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 our general partner prior to the acquisition and are not attributable to our limited partners.


44


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 appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Please read “Cautionary Statement Regarding Forward-Looking Statements.” Also, please read the risk factors and other cautionary statements described under the heading “Item 1A.—Risk Factors” included elsewhere in this Annual Report. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
Overview
We are a fee-based, growth-oriented limited partnership formed by Rice Energy (NYSE: RICE) to own, operate, develop and acquire midstream assets in the Appalachian Basin. Our assets consist of natural gas gathering, compression and water services assets servicing high quality producers in the rapidly developing dry gas cores of the Marcellus and Utica Shales. We provide our services under long-term, fee-based contracts, primarily to Rice Energy in its core operating areas.
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 Rice Energy 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 Rice Energy and third parties in the Appalachian Basin.
On September 26, 2016, we entered into a Purchase and Sale Agreement relating to the Vantage Midstream Asset Acquisition, as amended (the “Midstream Purchase Agreement”), with Rice Energy. Pursuant to the terms of the Midstream Purchase Agreement, we acquired the Vantage Midstream Entities from Rice Energy. Our acquisition of the Vantage Midstream Entities from Rice Energy is accounted for as a combination of entities under common control at historical cost. Please see “Item 8. Financial Statements—Notes to Consolidated Financial Statements—2. Acquisitions” for further detail regarding the Vantage Midstream Asset Acquisition.
Our Operations
Gas Gathering and Compression
Our gas gathering and compression assets are located within highly-concentrated acreage positions in the dry gas core of the Marcellus Shale and, as of December 31, 2016, consisted of a 4.1 MMDth/d high-pressure dry gas gathering system and associated compression in Washington and Greene Counties, Pennsylvania. The dry gas core of the Marcellus Shale in southwestern Pennsylvania is characterized by a combination of low development cost, consistently high production volumes and access to multiple takeaway pipelines, resulting in what Rice Energy believes to be among the highest rate of return wells.
We contract with Rice Energy 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 that we gather and compress generally requires no processing or treating prior to delivery into interstate takeaway pipelines.
We generate all of our gas gathering and compression revenues pursuant to long-term, fixed-fee contracts with Rice Energy and other high quality producers. We generate revenue primarily by charging fixed fees 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 Rice Energy and third parties, as well as to allow us to pursue volumes from additional third parties.
 

45


The following provides a summary of the key terms of our gas gathering and compression agreements as of December 31, 2016.
 
 
Remaining Term (Years)
 
Gathering Fee
 
Compression Fee (1)
 
Escalation /Adjustment Mechanism (2)
 
Dedicated Acres
Rice Energy
 
14
 
$0.30 / Dth
 
$0.07 / stage / Dth
 
Yes
 
Washington and Greene Counties (3)
Third Parties (4)(5)
 
10
 
$0.40 / Dth
 
varies
 
Yes
 
66,000 acres in Washington County
 
(1)
Compression fees under our gas gathering and compression agreements with Rice Energy and third parties are typically derived on a per stage basis. However, under certain of our third-party agreements, the per stage fees charged for compression varies depending on line pressure as opposed to being a flat fee per stage. Accordingly, the third-party compression fee is shown on a weighted average based on historical throughput.
(2)
The gathering and compression fees we receive under our gathering and compression agreements can be annually escalated based upon changes in the Consumer Price Index (“CPI”).
(3)
The dedicated area from Rice Energy excludes the first 20.0 MDth/d of Rice Energy’s Marcellus Shale dry gas production under an existing dedication to a third party in which Rice Energy owned approximately 9,000 gross acres as of December 31, 2016.
(4)
Amounts shown for third parties represent weighted averages based on historical throughput in the case of remaining term, gathering fee and compression fee (based on the period January 1, 2015 through December 31, 2016), and in the case of dedications, aggregate acres.
(5)
We manage credit risk of sales to third parties by limiting dealings to those third parties that meet 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. Our primary third-party customer engages in activities similar to those of Rice Energy and has a credit rating of Baa3 by Moody’s.
As we do not take ownership of the natural gas we gather and compress, we generally do not have direct exposure to fluctuations in commodity prices and basis differentials. 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” in the Annual Report.
Water Services
Our water services assets located in Washington and Greene Counties, Pennsylvania, and Belmont County, Ohio are 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 us and third parties in the Appalachian Basin. As of December 31, 2016, our Pennsylvania assets provided access to 22.5 MMgal/d of fresh water from the Monongahela River and several other regional water sources and our Ohio assets provided access to 14.0 MMgal/d of fresh water from the Ohio River and several other regional sources, both for distribution to the Rice Energy and third parties. Pursuant to the terms of a purchase and sale agreement (the “Purchase Agreement”) pursuant to which we acquired our water services assets from Rice Energy, Rice Energy has 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 and (ii) an option to purchase any water treatment facilities acquired by Rice Energy in such areas at its acquisition cost.
In connection with the closing of the acquisition of Rice Energy’s Pennsylvania and Ohio fresh water distribution systems and related facilities (the “Water Assets”), we entered into the Water Services Agreements with Rice Energy, whereby we agreed to provide certain fluid handling services to Rice Energy, including the exclusive right to provide fresh water for well completions operations and to collect and recycle or dispose of flowback and produced water for Rice Energy within areas of dedication in defined service areas in Pennsylvania and Ohio. The initial terms of the Water Services Agreements are until December 22, 2029 and from month to month thereafter. Under the agreements, Rice Energy pays us (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 and flowback hauling fee of actual out-of-pocket cost incurred by us, plus a 2% margin.

46


Our Predecessor
In January 2010, Rice Energy began constructing its natural gas gathering systems in southwestern Pennsylvania in conjunction with commencing horizontal development of its Marcellus Shale acreage. Rice Poseidon was formed in July 2013 to hold all of Rice Energy’s wholly-owned natural gas gathering, compression and fresh water distribution assets in Pennsylvania. At the time of Rice Poseidon’s formation, the only natural gas gathering, compression and fresh water distribution assets in Pennsylvania in which Rice Energy owned any interest that were not held directly by Rice Poseidon were the Alpha Assets, which are treated as having been acquired by our Predecessor upon Rice Energy’s acquisition of the remaining 50% interest in Alpha Shale Resources, LP (“Alpha Shale”) from a third party in January 2014. Prior to the formation of Rice Poseidon, the assets of Rice Poseidon were owned by various subsidiaries of Rice Energy.
As it relates to our Predecessor, when discussing periods:
prior to January 29, 2014, refers to the natural gas gathering, compression and water distribution assets and operations of Rice Poseidon;
subsequent to January 29, 2014 through April 17, 2014, refers collectively to the natural gas gathering, compression and water distribution assets and operations of Rice Poseidon taken together with the Alpha Assets; and
 
subsequent to April 17, 2014 up to December 22, 2014, refers collectively to the natural gas gathering, compression and water distribution assets and operations of Rice Poseidon, the Alpha Assets and the Momentum Assets (described below) from their respective dates of acquisition.
Subsequent to January 29, 2014, our Predecessor includes the Alpha Assets, which consist of certain natural gas gathering and compression assets held in Alpha Shale, a wholly-owned subsidiary of Rice Energy. Prior to January 29, 2014, each of Rice Energy and a third party owned a 50% interest in Alpha Shale, a joint venture formed to develop natural gas acreage in the Marcellus Shale. On January 29, 2014, in connection with the completion of its IPO, Rice Energy acquired the remaining 50% interest in Alpha Shale.
In addition, on April 17, 2014, Rice Poseidon acquired, from M3 Appalachia Gathering LLC, the Momentum Assets, which consist of a 28-mile, 6- to 16-inch gathering system in eastern Washington County, Pennsylvania, and permits and rights of way in Washington and Greene Counties, Pennsylvania, necessary to construct an 18-mile, 30-inch gathering system connecting the Washington County system to TETCO.
Our Predecessor included certain fresh water distribution assets and operations in Pennsylvania that were distributed to Rice Midstream Holdings concurrently with the closing of our IPO. On November 4, 2015, we entered into the Purchase Agreement with Rice Energy, pursuant to which we acquired the Water Assets. Rice Energy has 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 Water Services Agreements (defined below) and (ii) an option to purchase any water treatment facilities acquired by Rice Energy in such areas at Rice Energy’s acquisition cost. The acquisition of the Water Assets was accounted for as a combination of entities under common control, and as such, our consolidated financial statements have been retrospectively recast for all periods presented to include the historical results of the Water Assets.
Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations
Our future results of operations may not be comparable to the historical results of operations of our Predecessor presented below for the following reasons:
Revenues. There are differences in the way our Predecessor recorded revenues and the way we record revenues. As our assets have historically been a part of the integrated operations of Rice Energy, our Predecessor generally recognized only the costs and did not record revenue associated with the gathering, compression and water services provided to Rice Energy on an intercompany basis. Accordingly, the revenues in our historical consolidated financial statements for periods prior to December 22, 2014 relate generally only to amounts received from third parties for these services. Following our IPO, our revenues are generated by existing third-party gas gathering, compression and water services contracts, the gas gathering and compression agreement with Rice Energy and the water services agreements that we entered into with Rice Energy in connection with the closing of our IPO. In connection with the acquisition of the Water Assets, we amended and restated our Water Services Agreements, which altered the fee structure for water services. For additional information regarding our amended and restated Water Services Agreements, please refer to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Operations.”
Midstream Build-out. All of the natural gas gathering, compression and water assets of our Predecessor have been constructed in the last five years. As of December 31, 2016, the aggregate capacity on our natural gas gathering systems was 4.1 MMDth/d. Average daily throughput on our natural gas gathering systems increased from 647 MDth/d for the year ended

47


December 31, 2015 to 983 MDth/d for the year ended December 31, 2016, a 52% increase. Similarly, our fresh water distribution capacity increased to 36.5 MMgal/d as of December 31, 2016 from 19.4 MMgal/d as of December 31, 2015, an 88% increase. Cash capital expenditures with respect to our assets for the year ended December 31, 2016 and December 31, 2015 were $121.1 million and $248.5 million, respectively, and we expect to incur total capital expenditures of approximately $315.0 million for the year ending December 31, 2017.
Rice Energy’s Development Focus. With its operational focus on development, Rice Energy, our anchor customer, has focused almost exclusively on pad drilling, in which Rice Energy drills multiple wells on a single well pad (and a single receipt point for our gathering systems) as opposed to one or two wells per pad. As such, within our dedicated area, Rice Energy turned 50 gross (50 net) horizontal Marcellus wells into sales in the year ended December 31, 2016, which included 14 gross (14 net) producing wells acquired in connection with Rice Energy’s acquisition of Vantage and its subsidiaries (the “Vantage Acquisition”), as compared to 81 horizontal Marcellus and Upper Devonian wells over the preceding 6 years.
Common Control Transactions. Pursuant to the terms of the Purchase Agreement, on November 4, 2015, we acquired the Water Assets from Rice Energy. Our combined financial statements have been retrospectively recast for all periods prior to the acquisition of the Water Assets to include the historical results of the Water Assets as the transaction was accounted for as a combination of entities under common control. In addition, our 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.
General and Administrative Expenses. Our Predecessor’s general and administrative expenses included direct and indirect charges for the management of our assets and certain expenses allocated by Rice Energy for general corporate services, such as treasury, accounting and legal services. These expenses were charged or allocated to our Predecessor based on the nature of the expenses and Rice Energy’s estimate of the expense attributable to our Predecessor’s operations. Under our Omnibus Agreement with Rice Energy, Rice Energy charges us a combination of direct and allocated charges for general and administrative services. We also incur incremental general and administrative expenses attributable to operating as a publicly traded partnership, such as costs associated with: annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance expenses; and director compensation.

Financing. There are differences in the way we will finance our operations as compared to the way our Predecessor financed its operations. Historically, our Predecessor’s operations were financed as part of Rice Energy’s integrated operations and our Predecessor did not record any separate costs associated with financing its operations. Additionally, our Predecessor’s largely relied on capital contributions from Rice Energy to satisfy its capital expenditure requirements. For purposes of our Predecessor’s historical financial statements, we have recorded our proportionate share of Rice Energy’s interest based upon Rice Energy’s estimate of the expense attributable to our operations. Based on the terms of our cash distribution policy, we expect that we will distribute most of the cash generated by our operations to our unitholders. As a result, we expect to fund future growth capital expenditures primarily from a combination of borrowings under our revolving credit facility and the issuance of additional equity or debt securities.
How We Evaluate Our Operations
We evaluate our business on the basis of the following key measures:
our gathering throughput and fresh water services volumes;
our operating expenses; and
our Adjusted EBITDA.
Gathering Throughput and Fresh Water Services Volumes
Our management analyzes our performance based on the aggregate amount of throughput volumes on our gathering systems and volumes of fresh water distributed on our fresh water distribution systems. We must connect additional wells or well pads within our dedicated areas in order to maintain or increase volumes on our systems as a whole. Our success in connecting additional wells is impacted by successful drilling and completion activity on the acreage dedicated to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage, our ability to provide water services to new wells in support of well completion activities, our ability to attract volumes currently serviced by our competitors and our ability to cost-effectively construct new infrastructure to connect new wells.

48


Operating Expenses
Our management seeks to maximize the profitability of our operations in part by minimizing operating expenses. These expenses are comprised primarily of field operating costs (which include labor and measurement services, among other items), compression, pumping and procurement expense and other operating costs, some of which are independent of the volumes through our systems but fluctuate depending on the scale of our operations during a specific period.
We plan to utilize Rice Energy’s operational, technical and administrative personnel to enhance our operating efficiency and overall asset utilization. In some instances, these services are available to us at a low cost compared to the expense of developing these functions internally, and we intend to use Rice Energy personnel for many general and administrative services that represent a significant expense for competing midstream businesses.
Adjusted EBITDA
We define Adjusted EBITDA as net income (loss) before interest expense, income tax benefit (expense), depreciation expense, amortization of intangible assets, non-cash equity compensation expense, amortization of deferred financing costs and certain other items management believes affect the comparability of our operating results. Please see “Item 6. Selected Financial Data—Non-GAAP Financial Measures” for more information on Adjusted EBITDA.
Results of Operations
The following table sets forth selected consolidated operating data for the year ended December 31, 2016 compared to the year ended December 31, 2015 and for the year ended December 31, 2015 compared to the year ended December 31, 2014:
 
Year Ended December 31,
 
 
 
Year Ended December 31,
 
Change
 
2016
 
2015
 
Change
 
2015
 
2014
 
Statement of operations: (in thousands)
 
 
 
 
 
 
 
 
 
 
 
Operating revenues:
 
 
 
 
 
 
 
 
 
 
 
Affiliate
$
152,260

 
$
93,668

 
$
58,592

 
$
93,668

 
$
1,863

 
$
91,805

Third-party
49,363

 
20,791

 
28,572

 
20,791

 
4,585

 
16,206

Total operating revenues
201,623

 
114,459

 
87,164

 
114,459

 
6,448

 
108,011

 
 
 
 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
Operation and maintenance expense
24,608

 
14,910

 
9,698

 
14,910

 
4,773

 
10,137

General and administrative expense
21,613

 
17,895

 
3,718

 
17,895

 
11,922

 
5,973

Incentive unit expense

 
1,044

 
(1,044
)
 
1,044

 
13,480

 
(12,436
)
Depreciation expense
25,170

 
16,399

 
8,771

 
16,399

 
4,165

 
12,234

Acquisition costs
125

 

 
125

 

 
1,519

 
(1,519
)
Amortization of intangible assets
1,634

 
1,632

 
2

 
1,632

 
1,156

 
476

Other expense
1,531

 
543

 
988

 
543

 

 
543

Total operating expenses
74,681

 
52,423

 
22,258

 
52,423

 
37,015

 
15,408

 
 
 
 
 
 
 
 
 
 
 
 
Operating income (loss)
126,942

 
62,036

 
64,906

 
62,036

 
(30,567
)
 
92,603

Other income (expense)
78

 
11

 
67

 
11

 
(110
)
 
121

Interest expense
(3,931
)
 
(3,164
)
 
(767
)
 
(3,164
)
 
(13,571
)
 
10,407

Amortization of deferred financing costs
(1,479
)
 
(576
)
 
(903
)
 
(576
)
 

 
(576
)
Income (loss) before income taxes
121,610

 
58,307

 
63,303

 
58,307

 
(44,248
)
 
102,555

Income tax (expense) benefit

 
(5,812
)
 
5,812

 
(5,812
)
 
12,920

 
(18,732
)
Net income (loss)
$
121,610

 
$
52,495

 
$
69,115

 
$
52,495

 
$
(31,328
)
 
$
83,823

Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015
Operating revenues. Operating revenues increased from $114.5 million for the year ended December 31, 2015 to $201.6 million for the year ended December 31, 2016, an increase of $87.2 million, or 76%. The increase in operating revenues primarily relates to increased gathering and compression revenues associated with a 52% and 794% increase in period over period gathering and compression throughput, respectively. In addition, the increase relates to a $32.3 million increase in water services revenue due to a 61% increase in fresh water distribution volumes from 777 MMgal in 2015 to 1.3 Bgal in 2016. In addition, post-acquisition revenue associated with the Vantage Midstream Entities was $8.6 million for the period from October 19, 2016 through December 31, 2016.

49


Operation and maintenance expense. Total operation and maintenance expense increased from $14.9 million for the year ended December 31, 2015 to $24.6 million for the year ended December 31, 2016, an increase of $9.7 million, or 65%. 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.
General and administrative expense. General and administrative expense (before equity compensation expense) increased from $13.4 million for the year ended December 31, 2015 to $18.8 million for the year ended December 31, 2016, an increase of $5.4 million, or 40%. The increase year-over-year was primarily due to an increase in allocated costs associated with personnel and administrative expenses as the Rice Midstream Partners segment continues to grow. Included in general and administrative expense is equity compensation expense of $2.9 million and $4.5 million for the years ended December 31, 2016 and December 31, 2015, respectively.
Incentive unit expense. Incentive unit expense for the year ended December 31, 2015 of $1.0 million was allocated to the Water Assets by Rice Energy prior to their acquisition. No incentive unit expense was recorded for the year ended December 31, 2016.
Depreciation expense. Depreciation expense increased from $16.4 million for the year ended December 31, 2015 to $25.2 million for the year ended December 31, 2016, an increase of $8.8 million, or 53%. The increase year-over-year was primarily due to additional assets placed into service in 2016, including assets related to gathering, compression and water handling and treatment services, including those assets associated with the Vantage Midstream Asset Acquisition. For the year ended December 31, 2016, our gathering and water pipeline miles increased by 40% and 15%, respectively.
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 from Rice Energy. For the year ended December 31, 2016, the full amount of interest expense incurred related to borrowing with 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.
Income tax (expense) benefit. The $5.8 million income tax expense for the year ended December 31, 2015 was allocated to the Water Assets prior to their acquisition. Following our IPO, we are not subject to U.S. federal income tax and certain state income taxes due to our status as a partnership.
Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014
Operating revenues. Operating revenues increased from $6.4 million for the year ended December 31, 2014 to $114.5 million for the year ended December 31, 2015, an increase of $108.0 million. The increase year-over-year primarily relates to affiliate gathering revenues associated with our gathering agreement with Rice Energy and affiliate water service revenues associated with our water services agreements with Rice Energy, which were not in place prior to December 22, 2014. Additionally, the increase relates to gathering revenues associated with our existing third-party contracts acquired as part of the April 2014 acquisition of certain gas gathering assets in Washington and Greene Counties, Pennsylvania (the “Momentum Acquisition”).
Operation and maintenance expense. Total operation and maintenance expense increased from $4.8 million for the year ended December 31, 2014 to $14.9 million for the year ended December 31, 2015, an increase of $10.1 million. The increase was primarily due to an increase in contract labor expenses, additional leases on compression equipment and utility expenses.
General and administrative expense. General and administrative expense increased from $11.9 million for the year ended December 31, 2014 to $17.9 million for the year ended December 31, 2015, an increase of $6.0 million. The increase year-over-year was primarily related to costs associated with Rice Energy personnel that provide us support pursuant to our Omnibus Agreement. Included in general and administrative expense is equity compensation expense of $4.5 million and $0.8 million for the years ended December 31, 2015 and December 31, 2014, respectively.
Incentive unit expense. Incentive unit expense for the year ended December 31, 2014 was $13.5 million. These costs were allocated to us and to the Water Assets based on our estimate of the expense attributable to our operations. The payment obligation as it relates to the incentive units is with Rice Energy 2016 Irrevocable Trust and NGP Rice Holdings LLC (“NGP Holdings”) and will not be borne by Rice Energy or by us. Incentive unit expense for the year ended December 31, 2015 of $1.0 million was allocated to the Water Assets by Rice Energy prior to their acquisition.

50


Depreciation expense. Depreciation expense increased from $4.2 million for the year ended December 31, 2014 to $16.4 million for the year ended December 31, 2015, an increase of $12.2 million. The increase year-over-year was primarily due to additional assets placed into service in 2015, including assets related to the water services segment.
Acquisition costs. Acquisition costs for the year ended December 31, 2014 were $1.5 million. These costs were incurred in connection with the Momentum Acquisition.
Amortization of intangible assets. Amortization of intangible assets increased from $1.2 million for the year ended December 31, 2014 to $1.6 million for the year ended December 31, 2015. Intangible assets were acquired in connection with the Momentum Acquisition and are amortized over 30 years.
Interest expense. Interest expense decreased from $13.6 million for the year ended December 31, 2014 to $3.2 million for the year ended December 31, 2015, a decrease of $10.4 million. Interest expense for the year ended December 31, 2014 was charged by Rice Energy to us. 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 from Rice Energy.
Income tax (expense) benefit. The $12.9 million income tax benefit for the year ended December 31, 2014 was a result of the initial public offering and reorganization of Rice Energy as a corporation subject to U.S. federal income tax. The $5.8 million income tax expense for the year ended December 31, 2015 was allocated to the Water Assets prior to their acquisition. Following our IPO, 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 Rice Energy 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 Rice Energy and third parties in the Appalachian Basin.
We evaluate our business segments based on their contribution to our consolidated results based on operating income. Please see “Item 8. Financial Statements—Notes to Consolidated Financial Statements—10. Financial Information by Business Segment” for a reconciliation of each segment’s operating income to our consolidated operating income.

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The following table sets forth selected consolidated operating data for the year ended December 31, 2016 compared to the year ended December 31, 2015 and for the year ended December 31, 2015 compared to the year ended December 31, 2014:
Gathering and Compression Segment
 
Year Ended December 31,
 
 
 
Year Ended December 31,
 
Change
 
2016
 
2015
 
Change
 
2015
 
2014
 
Operating data:
 
 
 
 
 
 
 
 
 
 
 
Gathering volumes: (in MDth/d)
 
 
 
 
 
 
 
 
 
 
 
Affiliate
714

 
547

 
167

 
547

 
345

 
202

Third-party
269

 
100

 
169

 
100

 
33

 
67

Total gathering volumes
983

 
647

 
336

 
647

 
378

 
269

 
 
 
 
 
 
 
 
 
 
 
 
Compression volumes: (in MDth/d)
 
 
 
 
 
 
 
 
 
 
 
Affiliate
327

 
33

 
294

 
33

 

 
33

Third-party
245

 
31

 
214

 
31

 

 
31

Total compression volumes
572

 
64

 
508

 
64

 

 
64

 
 
 
 
 
 
 
 
 
 
 
 
Statement of operations data:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Gathering revenues:
 
 
 
 
 
 
 
 
 
 
 
Affiliate
77,625

 
59,734

 
17,891

 
59,734

 
1,863

 
57,871

Third-party
38,669

 
15,980

 
22,689

 
15,980

 
4,585

 
11,395

Total gathering revenues
116,294

 
75,714

 
40,580

 
75,714

 
6,448

 
69,266

 
 
 
 
 
 
 
 
 
 
 
 
Compression revenues:
 
 
 
 
 
 
 
 
 
 
 
Affiliate
8,722

 
1,445

 
7,277

 
1,445

 

 
1,445

Third-party
7,083

 
52

 
7,031

 
52

 

 
52

Total compression revenues
15,805

 
1,497

 
14,308

 
1,497

 

 
1,497

Total operating revenues
132,099

 
77,211


54,888


77,211


6,448


70,763

 
 
 
 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
Operation and maintenance expense
8,000

 
6,006

 
1,994

 
6,006

 
3,956

 
2,050

General and administrative expense
17,301

 
13,886

 
3,415

 
13,886

 
10,598

 
3,288

Incentive unit expense

 

 

 

 
11,974

 
(11,974
)
Depreciation expense
10,840

 
6,310

 
4,530

 
6,310

 
2,856

 
3,454

Acquisition costs
125

 

 
125

 

 
1,519

 
(1,519
)
Amortization of intangible assets
1,634

 
1,632

 
2

 
1,632

 
1,156

 
476

Other expense
1,051

 
492

 
559

 
492

 

 
492

Total operating expenses
38,951

 
28,326

 
10,625

 
28,326

 
32,059

 
(3,733
)
 
 
 
 
 
 
 
 
 
 
 
 
Operating income (loss)
$
93,148


$
48,885

 
$
44,263

 
$
48,885


$
(25,611
)
 
$
74,496

Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015
Gathering volumes. Gathering volumes increased from 647 MDth/d for the year ended December 31, 2015 to 983 MDth/d for the year ended December 31, 2016, a 52% increase. The increase in gathering volumes was primarily attributable to an increase in our existing third party contracts as well as an increase in gathering volumes associated with our gathering services agreement with Rice Energy. For the year ended December 31, 2016, Rice Energy turned to sales 51 gross (51 net) Appalachian wells, including 14 gross (14 net) producing wells as part of the Vantage Acquisition, all of which were located in acreage dedicated to us. In addition, post-acquisition revenue associated with the Vantage Midstream Entities was $8.6 million for the period from October 19, 2016 through December 31, 2016.
Compression volumes. Compression volumes increased from 64 MDth/d for the year ended December 31, 2015 to 572 MDth/d for the year ended December 31, 2016, a 794% increase. The increase in compression volumes was primarily due to the build-out of our compression assets in 2016, during which three new compressor stations were placed in service, as well as the acquisition of two compressor stations acquired in connection with the Vantage Midstream Asset Acquisition.

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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 period over period gathering and compression throughput, respectively.
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 (before equity compensation expense) expense increased from $10.0 million for the year ended December 31, 2015 to $15.0 million for the year ended December 31, 2016, an increase of $5.0 million, or 50%. The increase year-over-year was primarily due to an increase in allocated costs associated with personnel and administrative expenses as the Rice Midstream Partners segment continues 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%.
Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014
Gathering volumes. Gathering volumes increased from 378 MDth/d for the year ended December 31, 2014 to 647 MDth/d for the year ended December 31, 2015, an increase of 269 MDth/d. The increase was comprised of an increase in affiliate volumes of 202 MDth/d and third-party volumes of 67 MDth/d. The increase in affiliate gathering volumes was primarily attributable to the continued build-out of our gathering systems. The third-party volume increase was attributable to the Momentum Acquisition.
Operating revenues. Revenues from gathering and compression of natural gas increased from $6.4 million for the year ended December 31, 2014 to $77.2 million for the year ended December 31, 2015, an increase of $70.8 million. The increase year-over-year primarily relates to affiliate gathering revenues associated with our gathering agreement with Rice Energy, which was not in place prior to December 2014, and an increase in gathering revenues associated with our existing third-party contracts acquired in the Momentum Acquisition.
Operation and maintenance expense. Total operation and maintenance expense increased from $4.0 million for the year ended December 31, 2014 to $6.0 million for the year ended December 31, 2015, an increase of $2.1 million. The increase year-over-year was primarily due to increased expenses associated with the ongoing operation of the gathering assets including contract labor expenses and leases for compression equipment.
General and administrative expense. General and administrative expense increased from $10.6 million for the year ended December 31, 2014 to $13.9 million for the year ended December 31, 2015, an increase of $3.3 million. The increase year-over-year was primarily related to costs associated with Rice Energy personnel that provide us support pursuant to our Omnibus Agreement. Included in general and administrative expense is equity compensation expense of $3.9 million and $0.7 million for the years ended December 31, 2015 and December 31, 2014, respectively.
Incentive unit expense. Incentive unit expense for the year ended December 31, 2014 was $12.0 million. This expense was triggered by Rice Energy’s initial public offering in January 2014. These costs have been allocated to the gathering and compression segment based on our estimate of the expense attributable to our operations. The payment obligation as it relates to the incentive units is with Rice Energy 2016 Irrevocable Trust and NGP Holdings and will not be borne by Rice Energy or by us.
Depreciation expense. Depreciation expense increased from $2.9 million for the year ended December 31, 2014 to $6.3 million for the year ended December 31, 2015, an increase of $3.5 million. The increase year-over-year was primarily due to additional assets placed into service in 2015.
Acquisition costs. Acquisition costs for the year ended December 31, 2014 were $1.5 million. These costs were incurred in connection with the Momentum Acquisition.
Amortization of intangible assets. Amortization of intangible assets increased from $1.2 million for the year ended December 31, 2014 to $1.6 million for the year ended December 31, 2015. Intangible assets were acquired in connection with the Momentum Acquisition and are amortized over 30 years.

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Water Services Segment
 
Year Ended December 31,
 
 
 
Year Ended December 31,
 
Change
 
2016
 
2015
 
Change
 
2015
 
2014
 
Water services volumes: (in MMgal)
 
 
 
 
 
 
 
 
 
 
 
Affiliate
1,121

 
600