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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2013
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: 001-35666
Summit Midstream Partners, LP
(Exact name of registrant as specified in its charter)
Delaware  
(State or other jurisdiction of
 
incorporation or organization)
 
45-5200503  
(I.R.S. Employer
Identification No.)
 
 
 
2100 McKinney Avenue, Suite 1250
Dallas, Texas
 
(Address of principal executive offices)
 
75201  
(Zip Code)
 
 
 
Registrant’s telephone number, including area code: (214) 242-1955
 
 
 
Securities registered pursuant to Section 12(b) of the Act:
 
 
 
Title of each class
 
Name of exchange on which registered
Common Units
 
New York Stock Exchange
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
o Yes      x No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Act.
o Yes      x No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes      o 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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
x Yes      o No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer   o
Accelerated Filer x
Non-Accelerated Filer   o  (Do not check if a smaller reporting company)
Smaller Reporting Company   o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes x No
The aggregate market value of the common units held by non-affiliates of the registrant as of June 30, 2013, was $495,695,516.
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Class
 
As of February 28, 2014
Common Units
 
29,079,866 units
Subordinated Units
 
24,409,850 units
General Partner Units
 
1,091,453 units




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FORWARD-LOOKING STATEMENTS
Investors are cautioned that certain statements contained in this report as well as in periodic press releases and certain oral statements made by our officials during our presentations are “forward-looking” statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will continue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would,” and “could.” In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us or our subsidiaries, are also forward-looking statements. These forward-looking statements involve external risks and uncertainties, including, but not limited to, those described under the section entitled “Risk Factors” included herein.
Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond the control of our management team.  All forward-looking statements in this report and subsequent written and oral forward-looking statements attributable to us, or to persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements in this paragraph.  These risks and uncertainties include, among others:
changes in general economic conditions;
fluctuations in crude oil, natural gas and natural gas liquids prices;
the extent and success of drilling efforts, as well as the extent and quality of natural gas volumes produced within proximity of our assets;
failure or delays by our customers in achieving expected production in their natural gas and crude oil projects;
competitive conditions in our industry and their impact on our ability to connect natural gas supplies to our gathering and compression assets or systems;
actions or inactions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters and customers, including the inability or failure of our shipper customers to meet their financial obligations under our gathering agreements;
our ability to consummate acquisitions, successfully integrate the acquired businesses, realize any cost savings and other synergies from any acquisition;
the ability to attract and retain key management personnel;
commercial bank and capital market conditions and the potential impact of changes or disruptions in the credit and/or capital markets;
changes in the availability and cost of capital, and the results of our financing efforts, including availability of funds in the credit and/or capital markets;
restrictions placed on us by the agreements governing our debt instruments;
the availability, terms and cost of downstream transportation and processing services;
operating hazards, natural disasters, accidents, weather-related delays, casualty losses and other matters beyond our control;
weather conditions and seasonal trends;
timely receipt of necessary government approvals and permits, our ability to control the costs of construction, including costs of materials, labor and rights-of-way and other factors that may impact our ability to complete projects within budget and on schedule;
the effects of existing and future laws and governmental regulations, including environmental and climate change requirements;
the effects of litigation; and
certain factors discussed elsewhere in this report.
Developments in any of these areas could cause actual results to differ materially from those anticipated or projected or cause a significant reduction in the market price of our common units and senior notes. 

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The foregoing list of risks and uncertainties may not contain all of the risks and uncertainties that could affect us. In addition, in light of these risks and uncertainties, the matters referred to in the forward-looking statements contained in this document may not in fact occur. Accordingly, undue reliance should not be placed on these statements. We undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as otherwise required by law.

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GLOSSARY OF TERMS
adjusted EBITDA: EBITDA plus unit-based compensation, adjustments related to minimum volume commitment shortfall payments and loss on asset sales, less gain on asset sales
AMI : area of mutual interest
condensate: a natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions
distributable cash flow: adjusted EBITDA plus cash interest income, less cash paid for interest expense and income taxes, senior notes interest expense and maintenance capital expenditures
dry gas: a gas primarily composed of methane where heavy hydrocarbons and water either do not exist or have been removed through processing
EBITDA: net income, plus interest expense, income tax expense, and depreciation and amortization expense, less interest income and income tax benefit
end users: the ultimate users and consumers of transported energy products
Mcf: one thousand cubic feet
MMBtu: one million British Thermal Units
MMcf: one million cubic feet
MMcf/d: one million cubic feet per day
MVC: minimum volume commitment
NGLs: natural gas liquids; the combination of ethane, propane, normal butane, iso-butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature
NYMEX: New York Mercantile Exchange
play: a proven geological formation that contains commercial amounts of hydrocarbons
receipt point: the point where production is received by or into a gathering system or transportation pipeline
residue gas: the natural gas remaining after being processed or treated
tailgate: refers to the point at which processed natural gas and NGLs leave a processing facility for end-use markets
Tcf: one trillion cubic feet
throughput volume: the volume of natural gas transported or passing through a pipeline, plant or other facility during a particular period
wellhead: the equipment at the surface of a well used to control the well's pressure; also, the point at which the hydrocarbons and water exit the ground


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PART I
Item 1. Business.
Summit Midstream Partners, LP ("SMLP") is a Delaware limited partnership that completed its initial public offering ("IPO") in October 2012 to become a publicly traded entity. Summit Midstream Partners, LLC ("Summit Investments") is a Delaware limited liability company and the predecessor for accounting purposes (the "Predecessor") of SMLP. References to the "Company," "we," or "our," when used for dates or periods ended on or after the IPO, refer collectively to SMLP and its subsidiaries. References to the "Company," "we," or "our," when used for dates or periods ended prior to the IPO but after September 3, 2009, refer collectively to Summit Investments and its subsidiaries. References to the "Initial Predecessor" refer to the predecessor of Summit Investments and its affiliates and represent our operations from January 1, 2009 to September 3, 2009.
Immediately prior to the closing of the IPO, Summit Investments conveyed an interest in Summit Midstream Holdings, LLC ("Summit Holdings") to Summit Midstream GP, LLC (our "general partner") as a capital contribution; our general partner conveyed its interest in Summit Holdings to SMLP; and Summit Investments conveyed its remaining interest in Summit Holdings to SMLP. The historical financial statements contained in this Form 10-K reflect (i) the assets, liabilities and operations of SMLP for dates or periods beginning on or after October 3, 2012, (ii) the assets, liabilities and operations of Summit Investments (excluding the results of operations of assets outside of Summit Holdings that were retained by Summit Investments) for dates or periods ending before October 3, 2012 and after September 3, 2009 and (iii) the assets, liabilities and operations of our Initial Predecessor for dates or periods ending before September 3, 2009 and beginning on or after January 1, 2009.
In March 2013, Summit Investments contributed the ownership of its SMLP common and subordinated units along with its 2% equity interests in the general partner of SMLP (including the incentive distribution rights, or "IDRs" in respect of SMLP) to Summit Midstream Partners Holdings, LLC ("SMP Holdings") in exchange for a continuing 100% interest in SMP Holdings.
References in this Form 10-K to "Energy Capital Partners" refer collectively to Energy Capital Partners II, LLC and its parallel and co-investment funds. References in this Form 10-K to "GE Energy Financial Services" refer collectively to GE Energy Financial Services, Inc. References in this Form 10-K to our "Sponsors" refer collectively to Energy Capital Partners and GE Energy Financial Services.

Overview
SMLP is a growth-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in North America. We provide natural gas gathering, treating and compression services pursuant to long-term, primarily fee-based natural gas gathering agreements with our customers and counterparties. We generally refer to all of the services provided as gathering services.
Our results are driven primarily by the volumes of natural gas that we gather across our systems. During the year ended December 31, 2013, we generated approximately 96% of our revenue, net of pass-through items, from fee-based gathering services. We currently operate in four unconventional resource basins:
the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia;
the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;
the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and
the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado.
As of December 31, 2013, our gathering systems and the basins they serve were as follows:
the Mountaineer Midstream system, which serves the Appalachian Basin;
the Bison Midstream system, which serves the Williston Basin;
the DFW Midstream system, which serves the Fort Worth Basin; and
the Grand River system, which serves the Piceance Basin.

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As of December 31, 2013, our gathering systems had approximately 804 miles of pipeline and 182,460 horsepower of compression. During 2013, we gathered an average of 990 MMcf/d of natural gas, of which approximately 60% was delivered to third-party natural gas processing facilities.
We generate a substantial majority of our revenue under long-term, primarily fee-based natural gas gathering agreements. The fee-based nature of these agreements enhances the stability of our cash flows by limiting our direct commodity price exposure. Our customers and counterparties include affiliates and/or subsidiaries of some of the largest crude oil and natural gas producers in North America. As of December 31, 2013, we had a diverse group of customers and counterparties, including our four anchor customers: Antero Resources Corp. ("Antero"), Chesapeake Energy Corporation ("Chesapeake"), Encana Corporation ("Encana"), and EOG Resources, Inc. ("EOG"). A significant percentage of our revenue is attributable to these anchor customers. For the year ended December 31, 2013, customers that accounted for 10% or more of total revenues were Chesapeake and Encana. For additional information, see Note 9 to the audited consolidated financial statements.
Substantially all of our gas gathering agreements include areas of mutual interest ("AMIs"). Areas of mutual interest require that any production from natural gas wells drilled by our customers within the AMI be shipped on our gathering systems. Our AMIs cover more than 1.0 million acres in the aggregate and have remaining terms that range from three years to 23 years.
In addition, most of our gas gatherings agreements include minimum volume commitments ("MVCs") or minimum revenue commitments. We generally refer to MVCs and minimum revenue commitments collectively, as MVCs. An MVC contractually obligates our customers to ship a minimum quantity of natural gas or make payments to cover the shortfall of natural gas not shipped, either on a monthly or annual basis. We have designed our minimum volume commitment provisions to ensure that we will generate a certain amount of revenue from each customer over the life of the respective gas gathering agreement, whether by collecting gathering fees on actual throughput or from cash payments to cover any minimum volume commitment shortfall. As of December 31, 2013, we had remaining minimum volume commitments totaling 3.6 Tcf with remaining terms that range from three years to 13 years. Our minimum volume commitments have a weighted-average remaining life of 10.2 years (assuming minimum throughput volume for the remainder of the term) and average approximately 1,034 MMcf/d through 2018.
We are positioned for growth through the increased utilization and further development of our existing gathering system assets. In addition, we intend to grow our business through the execution of new, and the expansion of existing, strategic partnerships with large producers to provide midstream services for their upstream projects. We also intend to continue expanding our operations and diversifying our geographic footprint through asset acquisitions from Summit Investments and third parties, although Summit Investments has no obligation to offer any assets to us in the future and we have no obligation to acquire any assets that are offered to us.
Our Midstream Assets
Our midstream assets currently consist of the following four natural gas gathering systems:
Mountaineer Midstream System. The Mountaineer Midstream system is located in the Appalachian Basin and currently serves Antero, which is targeting liquids-rich natural gas production from the Marcellus Shale formation in Harrison and Doddridge counties in West Virginia. The Mountaineer Midstream system serves as a critical inlet to the Sherwood Processing Complex, a primary destination for liquids-rich natural gas in northern West Virginia. The Sherwood Processing Complex is owned and operated by MarkWest Energy Partners, L.P. (“MarkWest”). We are currently in the process of expanding throughput capacity on the Mountaineer Midstream system from 550 MMcf/d to 1,050 MMcf/d to support Antero's current and future anticipated drilling activities in this prolific region of the Marcellus Shale Play.
Bison Midstream System. The Bison Midstream system is located in the Williston Basin and currently serves producers that are targeting the Bakken and Three Forks shale formations in Mountrail and Burke counties in northwestern North Dakota. These formations are primarily targeted for crude oil production and producer drilling decisions are based largely on the prevailing price of crude oil. The Bison Midstream system gathers and compresses associated natural gas that exists in the crude oil production stream. Natural gas gathered on the Bison Midstream system is delivered to Aux Sable Midstream LLC's ("Aux Sable") Palermo Conditioning Plant in Palermo, North Dakota. Once conditioned, the natural gas is delivered to Aux Sable pipelines serving its 2.1 Bcf/d natural gas processing plant in Channahon, Illinois. We believe that the pace of drilling activity and thus, natural gas volume throughput on the Bison Midstream system, will primarily depend on the price of crude oil, which provides diversity of commodity price exposure for us relative to our other natural gas midstream operations.

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DFW Midstream System. The DFW Midstream system is primarily located in southeastern Tarrant County, the largest natural gas producing county in Texas. We consider this area to be the core of the core of the Barnett Shale because of the quality of the geology and the high production profile of the wells drilled to date. The DFW Midstream system currently has five primary interconnections with third-party, intrastate pipelines. These interconnections enable us to connect our customers, directly or indirectly, with the major natural gas market hubs of Waha, Carthage, and Katy in Texas, and Perryville and Henry Hub in Louisiana. We believe that the AMIs underpinning our system are substantially undeveloped compared with other areas in the Barnett Shale due to the historical lack of gathering infrastructure. Our AMIs and our system footprint provide us with a competitive advantage to add additional producers and incremental volumes in this core area of the Barnett Shale at a competitive capital cost.
Grand River System. The Grand River system is located in the Piceance Basin in western Colorado and currently serves producers targeting the liquids-rich Mesaverde formation. Natural gas gathered on the Grand River system is compressed, dehydrated, and discharged to a pipeline owned by Enterprise Products Partners L.P. ("Enterprise"), which connects to Enterprise's 1.7 Bcf/d processing facility located in Meeker, Colorado. The Grand River system also includes a new medium-pressure gathering system to handle future natural gas production from the emerging Mancos and Niobrara shale formations. We believe that the Grand River system is optimally located for expansion to gather production from these shale formations underlying the Mesaverde formation.
Organization and Results of Operations
SMLP was formed in May 2012 in anticipation of our IPO which closed on October 3, 2012. Since the IPO, we have issued additional common units and general partner interests in connection with two acquisitions. As of December 31, 2013, SMP Holdings held 14,691,397 SMLP common units, 24,409,850 SMLP subordinated units and 1,091,453 general partner units representing a 2% general partner interest in SMLP, along with all of the IDRs issued by SMLP. For additional information, see Notes 1, 6 and 13 to the audited consolidated financial statements.
Summit Investments, which owns SMP Holdings, and controls our general partner, was formed in 2009 by members of our management team and Energy Capital Partners. In August 2011, Energy Capital Partners sold a noncontrolling interest in Summit Investments to GE Energy Financial Services. Due to its ownership interest in Summit Investments and its representation on Summit Investments' board of managers, Energy Capital Partners controls our general partner and its activities, and as a result, SMLP.
We currently conduct our natural gas gathering operations in the midstream sector through our four natural gas gathering systems, each of which represents one of our four operating segments. Our operating segments reflect the way in which we internally report the financial information used to make decisions and allocate resources in connection with our operations. For disclosure purposes, we have aggregated these four operating segments into one reportable segment due to their similar characteristics and how we manage our business. The assets of each of our operating segments consist of natural gas gathering systems and related property, plant and equipment.
Our financial results are primarily driven by the volumes of natural gas that we gather across our systems and our management of operation and maintenance expense. We use a variety of financial and operational metrics to analyze our performance, including among others, throughput volume, operation and maintenance expense, EBITDA, adjusted EBITDA and distributable cash flow.
For additional information on our results of operations, EBITDA, adjusted EBITDA and distributable cash flow, see Item 6. Selected Financial Data, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A"), and the audited consolidated financial statements and notes thereto included in this report.

Industry Overview
General
The midstream segment of the natural gas industry is the link between the exploration and production of natural gas from the wellhead and the delivery of the natural gas and its other components to end-use markets. Companies within this industry create value at various stages along the natural gas value chain by gathering natural gas from producers at the wellhead, separating the hydrocarbons into dry gas (primarily methane) and NGLs and then routing the separated dry gas and NGLs streams for delivery to end-markets or to the next intermediate stage of the value chain. The following diagram illustrates the assets commonly found along the natural gas value chain:

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Midstream Services
The range of services utilized by midstream natural gas service providers are generally divided into the following six categories:
Gathering. At the initial stages of the midstream value chain, a network of typically small diameter pipelines known as gathering systems directly connect to wellheads, pad sites or other receipt points in the production area. These gathering systems transport natural gas from the wellhead to downstream pipelines or a central location for treating and processing. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow for additional production and well connections without significant incremental capital expenditures.
Compression. Gathering systems are operated at design pressures that enable the maximum amount of production to be gathered from connected wells. Through a mechanical process known as compression, volumes of natural gas at a given pressure are compressed to a sufficiently higher pressure, thereby allowing those volumes to be delivered to the market via a higher pressure downstream pipeline. Since wells produce at progressively lower field pressures as they age, it becomes necessary to add additional compression over time to maintain throughput across the gathering system.
Treating and Dehydration. Another process in the midstream value chain is treating and dehydration. Treating and dehydration involves the removal of impurities such as water, carbon dioxide, nitrogen and hydrogen sulfide, which may be present when natural gas is produced at the wellhead. These impurities must be removed for the natural gas to meet the specifications for transportation on long-haul intrastate and interstate pipelines. Moreover, end users will not purchase natural gas with high levels of impurities.
Processing. The principal components of natural gas are methane and ethane. Most natural gas also contains varying amounts of other NGLs, which are heavier hydrocarbons that are found in some natural gas streams. Even after treating and dehydration, some natural gas is not suitable for long-haul intrastate and interstate pipeline transportation or commercial use because it contains NGLs and condensate. This natural gas, referred to as liquids-rich natural gas, must also be processed to remove these heavier hydrocarbon components. NGLs not only interfere with pipeline transportation, but are also valuable commodities once removed from the natural gas stream. The removal and separation of NGLs usually takes place in a processing plant using industrial processes that exploit differences in the weights, boiling points, vapor pressures and other physical characteristics of NGL components.
Fractionation. Fractionation is the process by which NGLs are separated into individual liquid products for sale to petrochemical and industrial end users. The NGL components that can be separated in fractionation generally

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include: ethane, propane, normal butane, iso-butane and natural gasoline. This mixture of raw NGLs is often referred to as y-grade or raw natural gas liquid mix.
Transportation and Storage. After treating and dehydration, processing and fractionation, the natural gas and NGL components are stored, transported and marketed to end-use markets. Each pipeline system typically has storage capacity located both throughout the pipeline network and at major market centers to help temper seasonal demand and daily supply-demand shifts.
Contractual Arrangements
Midstream natural gas services, other than transportation and storage, are usually provided under contractual arrangements that vary in the amount of commodity price risk they carry. Three typical types of contracts are described below.
Fee-Based. Under fee-based arrangements, the service provider typically receives a fee for each unit of natural gas gathered and compressed at the wellhead and an additional fee per unit of natural gas treated or processed at its facility. As a result, the service provider bears no direct commodity price risk exposure. A substantial majority of our gas gathering agreements are fee based.
Percent-of-Proceeds. Under these arrangements, the service provider typically remits to the producers either a percentage of the proceeds from the sale of residue gas and/or NGLs or a percentage of the actual residue gas and/or NGLs at the tailgate. These types of arrangements expose the gatherer/processor to commodity price risk, as the revenues from the contracts directly correlate with the fluctuating price of natural gas and NGLs.
Keep-Whole. Under these arrangements, the service provider keeps 100% of the NGLs produced, and the processed natural gas, or value of the natural gas, is returned to the producer. Since some of the natural gas is used and removed during processing, the processor compensates the producer for the amount of natural gas used and removed in processing by supplying additional natural gas or by paying an agreed-upon value for the natural gas utilized. These arrangements have the highest commodity price exposure for the processor because the costs are dependent on the price of natural gas and the revenues are based on the price of NGLs.
Two typical forms of contracts utilized in the gathering, transportation and storage of natural gas are described below.
Firm. Firm service requires the reservation of pipeline capacity by a customer between certain receipt and delivery points. Firm customers generally pay a demand or capacity reservation fee based on the amount of capacity being reserved, regardless of whether the capacity is used, plus a usage fee based on the amount of natural gas transported. Firm storage contracts involve the reservation of a specific amount of storage capacity, including injection and withdrawal rights, and generally include a capacity reservation charge based on the amount of capacity being reserved plus an injection and/or withdrawal fee. The vast majority of our gas gathering agreements are firm.
Interruptible. Interruptible service is typically short-term in nature and is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers pay only for the volume of gas actually transported or stored. The obligation to provide this service is limited to available capacity not otherwise used by firm customers, and as such, customers receiving services under interruptible contracts are not assured capacity on the pipeline or at the storage facility.

Business Strategies
Our principal business strategy is to increase the amount of cash distributions we make to our unitholders over time. Our plan for continuing to execute this strategy includes the following key components:
Pursuing accretive acquisition opportunities from Summit Investments. We intend to pursue opportunities to expand our asset base by acquiring midstream assets owned and operated by and under development at Summit Investments. In addition to its significant ownership interest in us, Summit Investments owns and operates, and seeks to acquire and develop, crude oil, natural gas and water-related midstream assets in service and under construction in geographic areas in which we currently operate as well as in geographic areas outside of our current areas of operations. For example, in January 2014, Summit Investments acquired an interest in two entities (collectively, “Ohio Gathering”) that own, operate and are developing significant midstream infrastructure in southeastern Ohio consisting of a liquids-rich natural gas gathering system, a dry natural gas gathering system and a condensate transportation, storage

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and stabilization facility in the core of the Utica shale. While Summit Investments has indicated that it intends to offer us the opportunity to acquire its interests in Ohio Gathering, it is not under any contractual obligation to do so and we are unable to predict whether or when such opportunities may arise. In its role as a midstream development vehicle for our Sponsors, we believe that Summit Investments’ development efforts mitigate potential development and cash flow timing risks associated with large-scale greenfield development projects that would otherwise be borne by us.
Maintaining our focus on fee-based revenue with minimal direct commodity price exposure. As we expand our business, we intend to maintain our focus on providing midstream energy services under fee-based arrangements. Our midstream services are primarily provided under long-term, fee-based contracts with original terms ranging from five years to 25 years. We believe that our focus on fee-based revenues with minimal direct commodity exposure is essential to maintaining stable cash flows.
Capitalizing on organic growth opportunities to maximize throughput on our existing systems. We intend to continue to leverage our management team's expertise in constructing, developing and optimizing our midstream infrastructure assets to grow our business through organic development projects. We believe that our broad and geographically diverse operating footprint provides us with a competitive advantage to pursue organic development projects that are designed to extend our geographic reach, diversify our customer base, expand our midstream service offerings, increase the number of our hydrocarbon receipt points and maximize volume throughput.
Diversifying our asset base by expanding our midstream service offerings and exploring acquisition and development opportunities in various geographic areas. While our natural gas gathering operations in the Piceance Basin and the Barnett, Bakken and Marcellus shale plays currently represent our core business, we intend to diversify into other midstream services such as natural gas processing and crude oil gathering, through both greenfield development projects and acquisitions from affiliated and non-affiliated parties. We also intend to diversify our operations into other geographic regions.
Partnering with producers to provide midstream services for their development projects in high-growth, unconventional resource plays. We seek to promote commercial relationships with established and well-capitalized producers who are willing to serve as anchor customers and commit to long-term MVCs and AMIs. We will continue to pursue partnership opportunities with established producers to develop new infrastructure in unconventional resource basins that we believe will complement our existing midstream assets and/or enhance our overall business by facilitating our entry into new basins. These opportunities generally consist of a strategic acreage position in an unconventional resource play that is well-positioned for accelerated production but has limited existing midstream energy infrastructure to support such growth.

Competitive Strengths
We believe that we will be able to execute the components of our principal business strategy successfully because of the following competitive strengths:
Strategically located assets in core areas of prolific unconventional basins supported by partnerships with large producers. Our assets are strategically positioned within the core areas of four established unconventional resource plays. The geologic formations in the basins served by our assets have either relatively low drilling and completion costs, highly economic production profiles, or a combination of both which incentivize producers to develop more actively than in more marginal areas.
Fee-based revenues underpinned by long-term contracts with AMIs and MVCs. A substantial majority of our revenue for the year ended December 31, 2013 was generated under long-term, fee-based gas gathering agreements. We believe that long-term, fee-based gas gathering agreements enhance the stability of our cash flows by limiting our direct commodity price exposure.
Capital structure and financial flexibility. At December 31, 2013, we had $586.0 million of total indebtedness and the unused portion of our $700.0 million amended and restated revolving credit facility totaled $414.0 million. Under the terms of the revolving credit facility, our total leverage ratio (total net indebtedness to consolidated trailing 12-month EBITDA, as defined in the credit agreement) was approximately 3.7 to 1.0 at December 31, 2013, which compares with a total leverage ratio upper limit of not more than 5.0 to 1.0, or not more than 5.5 to 1.0 for up to 270 days following certain acquisitions (as defined in the credit agreement).

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Experienced management team with a proven record of asset acquisition, construction, development, operation and integration expertise. Our senior leadership team has an average of 19 years of energy experience and a proven track record of identifying and consummating significant acquisitions in addition to partnering with major producers to construct and develop midstream energy infrastructure.
Relationships with large and committed financial sponsors. Our Sponsors, Energy Capital Partners and GE Energy Financial Services, are experienced energy investors with proven track records of making substantial, long-term investments in high-quality energy assets. We believe the relationship with our Sponsors is a competitive advantage as they bring not only significant financial and management experience, but also numerous relationships throughout the energy industry that we believe will continue to benefit us as we seek to grow our business.

Our Midstream Assets
Our midstream assets currently consist of four natural gas gathering systems:
the Mountaineer Midstream system in northern West Virginia;
the Bison Midstream system in northwestern North Dakota;
the DFW Midstream system in north-central Texas; and
the Grand River system in western Colorado.
We earn revenue primarily from long-term, primarily fee-based gas gathering agreements with some of the largest and most active producers in our areas of operation. The fee-based nature of these agreements enhances the stability of our cash flows by limiting our direct commodity price exposure. The significant features of our gas gathering agreements and the gathering systems to which they relate are discussed in more detail below.
Areas of Mutual Interest
A substantial majority of our gas gathering agreements contain AMIs. The AMIs generally have original terms that range from five years to 25 years and require that any production by our customers within the AMIs will be shipped on our gathering systems. Our customers do not have leases that currently cover our entire AMIs but, to the extent that our customers lease additional acreage in the future within our AMIs, natural gas produced by our customers from that leased acreage will be gathered by our systems.
Under certain of our gas gathering agreements, we have agreed to construct pipeline laterals to connect our gathering systems to pad sites located within the AMI. If we choose not to participate in a discretionary opportunity presented by a customer, the customer may, in certain circumstances, construct the additional infrastructure and sell it to us at a price equal to their cost plus an applicable margin, or, in some cases, release the relevant acreage dedication from the AMI.
Minimum Volume Commitments
Our gas gathering agreements contain MVCs pursuant to which our customers guarantee to ship a minimum volume of natural gas on our gathering systems, or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. The original terms of the MVCs range from five to 15 years. In addition, certain of our customers have an aggregate MVC, which is a total amount of natural gas that the customer has agreed to ship on our gathering systems (or an equivalent monetary amount) over the MVC term. In these cases, once a customer achieves its aggregate MVC, any remaining future MVCs will terminate and the customer will then simply pay the applicable gathering rate multiplied by the actual throughput volumes shipped.
If a customer's actual throughput volumes are less than its MVC for the applicable period, it must make a shortfall payment to us at the end of that contract month or year, as applicable. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped for the applicable period and the MVC for the applicable period, multiplied by the applicable gathering fee. To the extent that a customer's actual throughput volumes are above or below its MVC for the applicable period, however, many of our gas gathering agreements contain provisions that can reduce or delay the cash flows that we expect to receive from our MVCs. These provisions include the following:
To the extent that a customer's throughput volumes are less than its MVC for the applicable period and the customer makes a shortfall payment, it may be entitled to an offset in one or more subsequent periods to

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the extent that its throughput volumes in subsequent periods exceed its MVC for those periods. In such a situation, we would not receive gathering fees on throughput in excess of a customer's monthly or annual MVC (depending on the terms of the specific gas gathering agreement) to the extent that the customer had made a shortfall payment with respect to one or more preceding months or years (as applicable).
To the extent that a customer's throughput volumes exceed its MVC in the applicable period, it may be entitled to apply the excess throughput against its aggregate MVC, thereby reducing the period for which its annual MVC applies. For example, one of our DFW Midstream customers has a contracted MVC term from October 2010 through September 2017. However, this customer has regularly shipped volumes in excess of its MVCs and satisfied the requirements of its aggregate MVC in less than three years. As a result of this mechanism, the weighted-average remaining period for which our MVCs apply is less than the weighted-average of the original stated contract terms of our MVCs.
To the extent that certain of our customers' throughput volumes exceed its MVC for the applicable period, there is a crediting mechanism that allows the customer to build a bank of credits that it can utilize in the future to reduce shortfall payments owed in subsequent periods, subject to expiration if there is no shortfall in subsequent periods. The period over which this credit bank can be applied to future shortfall payments varies, depending on the particular gas gathering agreement.
Mountaineer Midstream System
In June 2013, we acquired certain natural gas gathering pipelines and compression assets located in the liquids-rich area of the Marcellus Shale Play from from an affiliate of MarkWest for $210.0 million. We refer to these assets as the Mountaineer Midstream system. The Mountaineer Midstream system benefits from its location in Doddridge and Harrison counties in West Virginia where it gathers natural gas under a long-term contract with Antero. As of December 31, 2013, the Mountaineer Midstream system had approximately 41 miles of newly constructed, high-pressure natural gas gathering pipeline and two compressor stations with 21,060 horsepower of compression. This rich-gas gathering and compression system serves as a critical inlet to MarkWest's Sherwood Processing Complex, which is currently being expanded to a capacity of 1,000 MMcf/d. As of December 31, 2013, the Mountaineer Midstream system was capable of delivering 550 MMcf/d to the Sherwood Processing Complex. The Mountaineer Midstream system includes gathering lines ranging from 12 inches to 16 inches in diameter.
The following table provides information regarding our Mountaineer Midstream system as of December 31, 2013, except as noted.
Gathering system
 
Approximate length (Miles)
 
Compression (Horsepower)
 
Throughput capacity (MMcf/d)
 
Average
throughput
(MMcf/d)
(1)
Mountaineer Midstream
 
41
 
21,060
 
550
 
87
__________
(1) For the year ended December 31, 2013. For the period of SMLP's ownership in 2013, average throughput was 164 MMcf/d.
In November 2013, we amended our fee-based natural gas gathering agreement with Antero whereby we will construct approximately nine miles of high-pressure, 20-inch pipeline on the Mountaineer Midstream system (the "Zinnia Loop") to accommodate higher expected volume throughput from Antero. The Zinnia Loop will increase Mountaineer Midstream system’s throughput capacity from 550 MMcf/d to 1,050 MMcf/d. The project is underpinned by a new, 12-year, minimum revenue commitment from Antero, which extends the original term of the contract through 2026. We have commenced work on the project and expect to commission it in 2014. With this expansion, the Mountaineer Midstream system will enhance its strategic position as a primary source of natural gas deliveries to the Sherwood Processing Complex.
Bison Midstream System
In June 2013, we acquired certain associated natural gas gathering pipeline, dehydration and compression assets in the Williston Basin in northwestern North Dakota from SMP Holdings for $248.9 million. We refer to these assets as the Bison Midstream system. The Bison Midstream system gathers natural gas produced from the Bakken and Three Forks shale formations under long-term, primarily fee-based, contracts ranging from five years to 15 years. Since its acquisition, we have expanded the Bison Midstream system by adding pipeline and installing incremental compression horsepower. This system, which is located in Mountrail and Burke counties, comprised approximately 343 miles of low- and high-pressure pipeline and six compressor stations with approximately 7,800 horsepower of compression as of December 31, 2013 and includes gathering lines ranging from 3 inches to 10 inches in diameter.

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Natural gas gathered on the Bison Midstream system is delivered to Aux Sable’s Palermo Conditioning Plant in Palermo, North Dakota. Once conditioned, the natural gas is delivered on Aux Sable pipelines to its 2.1 Bcf/d natural gas processing plant in Channahon, Illinois.
The Bison Midstream system benefits from its location in Mountrail and Burke counties in North Dakota. Total throughput capacity on the system is in the process of being expanded to 30 MMcf/d with the installation of new compression which is expected to be completed by the end of 2014. Volume throughput on the Bison Midstream system is underpinned by MVCs from its anchor customer, EOG.
The following table provides information regarding our Bison Midstream system as of December 31, 2013, except as noted.
Gathering system
 
Approximate length (Miles)
 
Compression (Horsepower)
 
Throughput capacity (MMcf/d)
 
Average
throughput
(MMcf/d)
(1)
 
Approximate
areas of mutual interest (Acres)
 
Remaining MVCs (Bcf)
Bison Midstream
 
343
 
7,800
 
24
 
14
 
676,500
 
29
__________
(1) For the year ended December 31, 2013. For the period of SMLP's ownership in 2013, average throughput was 16 MMcf/d.
In addition to its gas gathering agreement with EOG, the Bison Midstream system is also supported by other fee-based and percent-of-proceeds gas gathering agreements with Cornerstone Natural Resources LLC, Hess Corporation, Hunt Oil Company, Statoil ASA and Oasis Petroleum Inc. As of December 31, 2013, these gas gathering agreements had remaining MVCs totaling approximately 29 Bcf and, through 2018, average approximately 14 MMcf/d. In addition, these gas gathering agreements have AMIs that cover approximately 676,500 net acres through 2027.
We continue to develop the Bison Midstream system to extend our gathering reach, diversify our customer base, increase our receipt points and maximize throughput. Since our acquisition, we have expanded and increased system reliability by adding pipeline, continuing to connect additional pad sites located within our areas of mutual interest, and installing additional compression. For the year ended December 31, 2013, the Bison Midstream system had average throughput of approximately 14 MMcf/d.
DFW Midstream System
In September 2009, we acquired approximately 17 miles of pipeline and 2,500 horsepower of electric-drive compression in north-central Texas from Energy Future Holdings Corp. ("Energy Future Holdings") and Chesapeake. We refer to these assets as the DFW Midstream system. Since the initial acquisition, we have expanded the DFW Midstream system by adding pipeline and installing incremental compression horsepower. As of December 31, 2013, the DFW Midstream system had approximately 119 miles of pipeline and three compressor stations with approximately 56,100 horsepower of compression. The DFW Midstream system includes gathering lines ranging from 8 inches to 30 inches in diameter and is located along existing electric transmission corridors and under both private and public property. The DFW Midstream system currently has five primary interconnections with third-party, intrastate pipelines. These interconnections enable us to connect our customers, directly or indirectly, with the major natural gas market hubs of Waha, Carthage, and Katy in Texas, and Perryville and Henry Hub in Louisiana.
The DFW Midstream system benefits from its location in southeastern Tarrant County, Texas, which is commonly referred to as the core of the Barnett Shale. Based on peak month average daily production rates sourced from the Railroad Commission of Texas as of December 2013, this area contains the most prolific wells in the Barnett Shale. For example, the two largest and four of the five largest wells drilled in the Barnett Shale (based on peak month average daily rates) are connected to the DFW Midstream system.
Development of the DFW Midstream system has enabled our customers to efficiently produce natural gas by utilizing horizontal drilling techniques from pad sites already connected or identified to be connected in our areas of mutual interest. Given the urban nature of southeastern Tarrant County, we expect that the majority of future natural gas drilling in this area will occur from existing pad sites. As a result, we believe we will be able to increase throughput and cash flows with minimal additional capital expenditures.

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The following table provides information regarding our DFW Midstream system as of December 31, 2013, except as noted.
Gathering system
 
Approximate length (Miles)
 
Compression (Horsepower)
 
Throughput capacity (MMcf/d)
 
Average
throughput
(MMcf/d)
(1)
 
Approximate
areas of mutual interest (Acres)
 
Remaining MVCs (Bcf)
DFW Midstream
 
119
 
56,100
 
450
 
391
 
107,300
 
263
__________
(1) For the year ended December 31, 2013.
In September 2009, we entered into a long-term, fee-based gas gathering agreement with Chesapeake as our anchor customer that included a 20-year area of mutual interest covering approximately 95,000 acres and a 10-year MVC totaling approximately 450 Bcf. In addition to Chesapeake, the DFW Midstream system is underpinned by seven other long-term, fee-based gas gathering agreements with Atlas Energy L.P., Beacon E&P Company, LLC, EnerVest, Ltd., EOG, Exxon Mobil Corporation, TOTAL, S.A. and Vantage Energy, LLC. As of December 31, 2013, DFW Midstream's gas gathering agreements had remaining MVCs totaling approximately 263 Bcf and, through 2018, average approximately 141 MMcf/d. In addition, these gas gathering agreements have areas of mutual interest that cover approximately 107,300 acres through 2030.
We designed the DFW Midstream system to benefit from incremental volumes arising from high-density, infill drilling on existing pad sites that are already connected to the gathering system and as such would not require significant additional capital expenditures. We continue to develop the DFW Midstream system to extend our gathering reach, diversify our customer base, increase our receipt points and maximize throughput. Since the acquisition, we have expanded this system by adding pipeline, continuing to connect additional pad sites located within our areas of mutual interest, and expanding the throughput capacity by installing additional electric-drive compression. We also recently constructed a 150 gallon per minute natural gas treating facility that will enable us to provide treating services that would otherwise be provided to our customers by third parties. The natural gas treating facility was commissioned in February 2014. We retain a small fixed percentage of the natural gas that we receive at the receipt points to offset the costs we incur to operate our electric-drive compressors. For the year ended December 31, 2013, the DFW Midstream system had average throughput of approximately 391 MMcf/d.
We believe the production profile of wells drilled within our areas of mutual interest and flowing on the DFW Midstream system will continue to attract drilling activity over the long term as producers become more selective in their drilling locations and focus on the core areas of certain basins to maximize their returns. We believe our strategic location in the Barnett Shale provides us with a competitive advantage to add incremental throughput with limited additional investment capital due to the anticipated future, high-density, infill drilling from our customers on connected pad sites and nearby pad sites that have yet to be connected. This high-density, infill drilling is magnified in our area given the urban landscape and the efforts of our producer customers to minimize their surface footprint.
Grand River System
In October 2011, we acquired certain natural gas gathering pipeline, dehydration and compression assets in the Piceance Basin in western Colorado from Encana Oil & Gas (USA) Inc., a subsidiary of Encana for $590.2 million. We refer to these assets as the Grand River system. The Grand River system, which gathers natural gas from the Mesaverde formation and the Mancos and Niobrara shale formations located within the Piceance Basin, comprised approximately 301 miles of pipeline and 97,500 horsepower of compression as of December 31, 2013. It is primarily located in Garfield County, the largest natural gas producing county in Colorado and is composed of three distinct gathering systems that service producers operating in: (i) the Mamm Creek Field, (ii) the South Parachute Field, and (iii) the Orchard Field. Natural gas gathered on these three systems is compressed, dehydrated, and discharged to a pipeline owned by Enterprise, which connects to Enterprise's 1.7 Bcf/d processing facility located in Meeker, Colorado. As of December 31, 2013, the Grand River system had aggregate throughput capacity of 885 MMcf/d.
The Grand River system is primarily a low-pressure gathering system that was originally designed to gather natural gas produced from traditional vertical wells targeting the liquids-rich Mesaverde formation. The Mesaverde is a shallow, tight sands geologic formation that producers have targeted with directional drilling for several decades. We also gather natural gas from our customers' wells targeting the deeper Mancos and Niobrara shale formations. Over the last three years, our customers have completed numerous horizontal wells targeting the emerging Mancos and Niobrara shale formations. These formations generally have higher initial production rates and lower Btu content than Mesaverde wells. Based on our customers' current drilling activities, we anticipate that the majority of

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our near-term throughput on the Grand River system will continue to originate from the Mesaverde formation. We expect to continue to pursue additional volumes on the low-pressure system to more fully utilize the existing throughput capacity.
The following table provides information regarding our Grand River system as of December 31, 2013, except as noted.
Gathering system
 
Approximate length (Miles)
 
Compression (Horsepower)
 
Throughput capacity (MMcf/d)
 
Average throughput (MMcf/d) (1)
 
Approximate areas of mutual interest (Acres)
 
Remaining MVCs (Bcf)
Mamm Creek
 
208
 
60,180
 
600
 
386
 
174,000
 
978
South Parachute
 
43
 
12,168
 
75
 
71
 
17,000
 

Orchard
 
50
 
25,152
 
210
 
41
 
39,000
 
825
Total Grand River system
 
301
 
97,500
 
885
 
498
 
230,000
 
1,803
__________
(1) For the year ended December 31, 2013.
In October 2011, we entered into a long-term, fee-based gas gathering agreement with Encana as our anchor customer that included a 25-year area of mutual interest covering approximately 187,000 acres and a 15-year MVC totaling approximately 1,558 Bcf. In addition to Encana, the Grand River system is underpinned by three other long-term, fee-based gas gathering and compression agreements with Bill Barrett Corporation, Ursa Resources Group II LLC and WPX Energy, Inc. These agreements include minimum volume commitments with original terms ranging from 10 to 15 years and areas of mutual interest with original terms ranging from 10 years to 25 years. We receive natural gas from these primary and other customers at nine central receipt points on the Grand River system. As of December 31, 2013, Grand River's gas gathering agreements had remaining MVCs totaling approximately 1,803 Bcf and areas of mutual interest that cover approximately 230,000 acres through 2036. Through 2018, the remaining MVCs are expected to average approximately 517 MMcf/d. For the year ended December 31, 2013, the Grand River system gathered an average of approximately 498 MMcf/d from the Mamm Creek, South Parachute and Orchard fields in the area around Rifle, Colorado.
We intend to expand the Grand River system by connecting additional pad sites within our areas of mutual interest, adding new customers, and acquiring nearby gathering systems. In addition to the underpinning provided by our gas gathering agreements, Encana's drilling program in the Mamm Creek and South Parachute fields is supported by its joint venture with Nucor Corporation, which specifies a minimum number of Mesaverde wells to be drilled.

Our Sponsors
Our Predecessor was formed in 2009 by members of our management and Energy Capital Partners, which together with its affiliated funds, is a private equity firm with over $13.0 billion in capital commitments that is focused on investing in North America's energy infrastructure. Energy Capital Partners has significant energy and financial expertise to complement its investment in us. As of December 31, 2013, Energy Capital Partners and its affiliated funds had 24 investment platforms with investments in the power generation, midstream oil and gas, electric transmission, energy equipment and services, environmental infrastructure and other energy related sectors of the energy industry.
In August 2011, Energy Capital Partners sold an interest in the Predecessor to GE Energy Financial Services. GE Energy Financial Services invests globally in essential, long-lived and capital-intensive energy assets. As of December 31, 2013, GE Energy Financial Services held approximately $18 billion in energy assets worldwide. GE Energy Financial Services has invested over $2.0 billion in midstream-related assets.
Summit Investments, which owns and controls our general partner, has an inventory of midstream assets comprising more than $2.0 billion of previous acquisitions and current and future development projects. In addition to its midstream assets located in the Piceance Basin in Colorado, the Uinta Basin in Utah and the Williston Basin in North Dakota, Summit Investments has also acquired an interest in two entities that own, operate and are developing significant midstream infrastructure in southeastern Ohio consisting of a liquids-rich natural gas gathering system, a dry natural gas gathering system and a condensate transportation, storage and stabilization facility in the core of the Utica Shale. All of these midstream assets offer opportunities for customer and service offering diversification into crude oil and water gathering and liquids rich gas processing. Furthermore, we believe

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they present an opportunity for our further geographic diversification due to their presence in the Piceance and Uinta basins in Colorado and Utah, the Bakken Shale Play in North Dakota, the DJ Niobrara Basin in Colorado and the Utica Shale Play in Ohio. While these assets have not been contributed to SMLP and SMP Holdings is not obligated to sell these assets to SMLP, we believe they may represent a future opportunity for execution of our business strategy.

Competition
We compete with other midstream companies, producers and intrastate and interstate pipelines. Competition for natural gas volumes is primarily based on reputation, commercial terms, service levels, access to end-use markets, location, available capacity, and fuel efficiencies. We may also face competition for production drilled outside of our areas of mutual interest and on attracting third-party volumes to our gathering systems. Additionally, we could face incremental competition to the extent we make acquisitions from third parties.

Regulation of the Oil and Natural Gas Industries
General. Sales by producers of natural gas, crude oil, condensate, and NGLs are currently made at market prices. However, gathering and transportation services are subject to various types of regulation, which may affect certain aspects of our business and the market for our services. The Federal Energy Regulatory Commission ("FERC") regulates the transportation of natural gas in interstate commerce and the interstate transportation of crude oil, petroleum products and NGLs. FERC regulation includes reviewing and accepting or approving rates and other terms and conditions for such transportation services. FERC is also authorized to prevent and sanction market manipulation in natural gas markets while the Federal Trade Commission is authorized to prevent and sanction market manipulation in petroleum markets. State and municipal regulations may apply to the production and gathering of natural gas, the construction and operation of natural gas and crude oil facilities, and the rates and practices of gathering systems and intrastate pipelines.
Regulation of Oil and Natural Gas Exploration, Production and Sales. Sales of crude oil and NGLs are not currently regulated and are transacted at market prices. In 1989, the U.S. Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting wellhead sales of natural gas. FERC, which has the authority under the Natural Gas Act to regulate the prices and other terms and conditions of the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all gas resellers subject to its regulation, except interstate pipelines, to resell natural gas at market prices. Either Congress or FERC (with respect to the resale of gas in interstate commerce), however, could re-impose price controls in the future.
Exploration and production operations are subject to various types of federal, state and local regulation, including, but not limited to, permitting, well location, methods of drilling, well operations, and conservation of resources. While these regulations do not directly apply to our business, they may affect our customers' ability to produce natural gas.
Regulation of the Gathering and Transportation of Natural Gas. We believe that our gas pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of FERC under the Natural Gas Act and the Natural Gas Policy Act of 1978 (the "NGPA"), although we are subject to FERC's anti-market manipulation regulations. The distinction between federally unregulated gathering facilities and FERC-regulated transmission pipelines has been the subject of extensive litigation and changes in the policies and interpretations of laws and regulations. In addition, the status of any individual gathering system may be determined by FERC on a case-by-case basis, although FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of gathering systems (including some of our pipelines) could change based on future determinations by FERC or the courts.
Intrastate pipelines, which may include some pipelines that perform gathering functions, may be subject to safety regulation by the U.S. Department of Transportation although typically state regulatory authorities (operating under a federal certification) perform this function. State regulatory authorities also have jurisdiction over the rates and practices of intrastate pipelines and gathering systems, including requirements for ratable takes or non-discriminatory access to pipeline services. The basis for state regulation and the degree of regulatory oversight of gathering systems and intrastate pipelines varies from state to state. In Texas, we are regulated as a gas utility and have filed tariffs with the Railroad Commission of Texas to establish rates and terms of service for our DFW Midstream system assets. We have not been required to file a tariff in Colorado for our Grand River system assets,

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nor have we been required to file a tariff in West Virginia or North Dakota for our operations in those states, although regulatory authorities in North Dakota have recently issued new rules requiring the submission of shape files to identify the location of underground gathering pipelines. The states in which we operate have adopted complaint-based regulation that allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve access issues and rate grievances, among other matters. State authorities in Texas, Colorado, North Dakota, and West Virginia generally have not initiated investigations of the rates or practices of gathering systems or intrastate pipelines in the absence of a complaint. State regulation of intrastate pipelines continues to evolve and may become more stringent in the future.
Natural gas production, gathering and transportation, including the construction of new gathering facilities and expansion of existing gathering facilities may also be subject to local regulation, such as approval and permit requirements.
Anti-Market Manipulation Rules. We are subject to the anti-market manipulation provisions in the Natural Gas Act and the NGPA, as amended by the Energy Policy Act of 2005, which authorize FERC to impose fines of up to $1,000,000 per day per violation of the Natural Gas Act, the NGPA, or their implementing regulations. In addition, the Federal Trade Commission holds statutory authority under the Energy Independence and Security Act of 2007 to prevent market manipulation in petroleum markets, including the authority to request that a court impose fines of up to $1,000,000 per violation. These agencies have promulgated broad rules and regulations prohibiting fraud and manipulation in oil and gas markets. The Commodity Futures Trading Commission (the "CFTC") is directed under the Commodity Exchange Act to prevent price manipulations in the commodity and futures markets, including the energy futures markets. Pursuant to statutory authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1,000,000 per day per violation or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the Commodity Exchange Act. We are also subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation.
Safety and Maintenance. We are subject to regulation by the U.S. Department of Transportation under the Natural Gas Pipeline Safety Act of 1968, as amended (the “NGPSA”) which establishes federal safety standards for the design, construction, operation and maintenance of natural gas pipeline facilities. In the Pipeline Safety Act of 1992, Congress expanded the U.S. Department of Transportation's regulatory authority to include regulated gathering lines that had previously been exempt from federal jurisdiction. The Pipeline Safety Improvement Act of 2002 and the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 established mandatory inspections for certain U.S. oil and natural gas transmission pipelines in high consequence areas. The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 reauthorizes funding for federal pipeline safety programs through 2015, 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 U.S. Department of Transportation has delegated the implementation of safety requirements to the Pipeline and Hazardous Materials Safety Administration (the "PHMSA"), which has adopted and enforces safety standards and procedures applicable to a limited number of our pipelines. In addition, many states, including the states in which we operate, have adopted regulations that are identical to or more restrictive than existing U.S. Department of Transportation regulations for intrastate pipelines. Among the regulations applicable to us, the PHMSA requires pipeline operators to develop integrity management programs for certain pipelines located in high consequence areas, which include high-population areas such as the Dallas-Fort Worth greater metropolitan area where our DFW gathering system is located. While the majority of our pipelines meet the U.S. Department of Transportation definition of gathering lines and are thus exempt from the integrity management requirements of the PHMSA, we also operate a limited number of pipelines that are subject to the integrity management requirements. Those regulations require operators, including us, to:
perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
maintain processes for data collection, integration and analysis;
repair and remediate pipelines as necessary;
adopt and maintain procedures, standards and training programs for control room operations; and

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implement preventive and mitigating actions.
The PHMSA published an advanced notice of proposed rulemaking to solicit comments on the need for changes to its safety regulations, including whether to revise the integrity management requirements. The notice also solicited comments on changes to the definition of gathering pipelines, which could subject many currently exempted pipelines to the PHMSA regulations. The PHMSA also recently published an advisory bulletin providing guidance on verification of records related to pipeline maximum allowable operating pressure. Pipelines that do not meet the PHMSA's record verification standards may be required to perform additional testing or reduce their operating pressures.
Gathering systems like ours are also subject to a number of federal and state laws and regulations, including the Federal Occupational Safety and Health Act and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, Environmental Protection Agency ("EPA") community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and the public.

Environmental Matters
General. Our operation of pipelines and other assets for the gathering, compressing and dehydration of natural gas and other products is 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 assets, 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 or otherwise restricting the way we operate or imposing additional costs on our operations;
limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;
delaying system modification or upgrades during permit reviews;
requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and
enjoining the operations of facilities deemed to be in non-compliance with permits or permit requirements issued pursuant to or 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. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
The trend in environmental regulation is to place more stringent requirements, resulting in more restrictions and limitations, on activities that may affect the environment. 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. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing and future regulations.
The following is a discussion of the material environmental laws and regulations that relate to our business.
Hazardous Substances and Waste. Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. Furthermore, the Toxic Substances Control Act, and analogous state laws, impose requirements on the use, storage and disposal of various chemicals

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and chemical substances at our facilities. The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA") and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. We may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
We also generate industrial wastes that are subject to the requirements of the Resource Conservation and Recovery Act and comparable state statutes. While the Resource Conservation and Recovery Act regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. We generate minimal hazardous waste; however, it is possible that non-hazardous wastes, which could include wastes currently generated during our operations, will in the future be designated as hazardous wastes and, therefore, be subject to more rigorous and costly disposal requirements. Moreover, from time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for non-hazardous wastes, including natural gas wastes.
We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although we believe that the previous operators utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. These properties and the wastes disposed thereon may be subject to CERCLA, the Resource Conservation and Recovery Act and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.
Oil Pollution Act. In 1991, the EPA adopted regulations under the Oil Pollution Act. These oil pollution prevention regulations, as amended several times since their original adoption, require the preparation of a Spill Prevention Control and Countermeasure (“SPCC”) plan for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility's operations comply with the requirements. To be in compliance, the facility's SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacility piping), inspections and records, security, and training. Most importantly, the facility must fully implement the SPCC plan and train personnel in its execution. We maintain and implement such plans for a number of our facilities.
Air Emissions. Our operations are subject to the federal Clean Air Act and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. Furthermore, we may be required to incur certain capital expenditures in the future to obtain and maintain operating permits and approvals for air pollutant emitting sources.
In April 2012, the EPA finalized rules that establish new air emission reporting, monitoring, and control requirements for oil and natural gas production and natural gas processing operations. Specifically, the EPA's rule package included New Source Performance Standards ("NSPS") to address emissions of sulfur dioxide and volatile organic compounds ("VOCs") from a number of sources that were previously not regulated in the oil and gas industry. Additionally, the EPA revised several existing regulations in this rulemaking effort to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules establish specific new requirements regarding emissions from compressors, pneumatic controllers, dehydrators, storage tanks and other production equipment. In addition, the rules establish new leak detection requirements for natural gas processing plants at 500 ppm. These rules will require a number of modifications to our operations, including

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the installation of new equipment to control emissions from VOC emitting tanks at initial startup. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs.
In addition, the EPA rules include NSPS for completions of hydraulically fractured natural gas wells, which will impact our upstream customers. Before January 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring using a completion combustion device or by capturing the gas using green completions with a completion combustion device, thereby capturing gas that would otherwise be flared. Beginning January 2015, operators must capture the gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured wells as well as existing wells that are refractured. These requirements may result in increased operating costs for producers who drill near our pipelines, which could reduce the volumes of natural gas available to move through our gathering systems.
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce emissions of GHGs in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs.
In November 2013, the Colorado Department of Public Health and Environmental (CDPHE) proposed a number of changes to existing statewide air emission regulations. This rulemaking was in response to the newly issued Federal regulations described above, and the State of Colorado’s obligation to either adopt the Federal Standards, or implement statewide standards which are as stringent or more stringent than the Federal standards. Colorado has proposed changes to its statewide regulations in an effort to reduce emissions of VOCs and other hazardous air pollutants from the production and processing sectors, as well as to comply with the newly issued NSPS. The proposed regulatory language will have significant impacts on both upstream and midstream operators throughout the state of Colorado. Notably, the rule, if adopted, will require all operators to implement a leak detection and repair program at all of their oil and gas facilities. Historically these leak detection and repair requirements have only applied to the natural gas processing sector and not upstream and/or gathering system operations. Summit expects to incur additional operating costs to comply with the revised regulations in Colorado.
The adoption of any legislation or regulations that requires reporting of greenhouse gases (“GHGs”) or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur significant added costs to reduce emissions of GHGs or could adversely affect demand for the natural gas and NGLs we gather and process or fractionate. Moreover, if Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products, which could adversely affect the services we provide. Finally, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate change that could have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if such effects were to occur, they could have an adverse effect on our operations.
Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the United States and impose requirements affecting our ability to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. We have discharge permits in place for our compression and processing facilities, as required. These permits require us to control storm water runoff from such facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
Hydraulic Fracturing. The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. We do not conduct any hydraulic fracturing activities. However, a portion of our customers' natural gas production is developed from unconventional

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sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of underground injection and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of the U.S. Congress. Congress will likely continue to consider legislation to amend the Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under the Act's Underground Injection Control Program to require disclosure of chemicals used in the hydraulic fracturing process.
The federal government is currently undertaking several studies of hydraulic fracturing's potential impacts. The EPA released a progress report on its study in December 2012 and stated that a draft report of the findings of the study is expected in late 2014. In addition, in October 2011, the EPA announced its intention to propose regulations by 2014 under the Clean Water Act to regulate wastewater discharges from hydraulic fracturing and other natural gas production activities. In May 2012, the Bureau of Land Management issued a proposed rule to regulate hydraulic fracturing on public and Indian land. The rule would require companies to publicly disclose the chemicals used in hydraulic fracturing operations to the Bureau of Land Management after fracturing operations have been completed and includes provisions addressing well-bore integrity and flowback water management plans. The final rule has not yet been published, but is expected sometime in 2014. Increased regulation of hydraulic fracturing could have an adverse effect on our upstream customers, thereby reducing the volumes of natural gas that we handle and having a potentially indirect adverse effect on our cash flows and results of our operations.
Several states, including Texas, Colorado, North Dakota, and West Virginia, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing through additional permit requirements, public disclosure of fracturing fluid contents, operational restrictions, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds.
In April 2012, the EPA approved final rules that would subject all oil and natural gas operations (production, processing, transmission, storage and distribution) to regulation under the NSPS and National Emission Standards for Hazardous Air Pollutants programs. These rules also include NSPS for completions of hydraulically fractured gas wells. These standards include the reduced emission completion techniques developed in the EPA ' s Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under the National Emission Standards for Hazardous Air Pollutants program include maximum achievable control technology standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to maximum achievable control technology standards. At this point, the effect these proposed rules could have on our business has not been determined. While these rules have been finalized, many of the rules ' provisions will be phased-in over time, with the more stringent requirements, including reduced emission completion, not becoming effective until 2015.
Endangered Species Act. The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. Some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species.
National Environmental Policy Act. The National Environmental Policy Act (the "NEPA"), establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA and, as a result, many activities requiring FERC approval must undergo NEPA review. Many of our activities are covered under categorical exclusions which results in a shorter NEPA review process. The Council on Environmental Quality has announced an intention to reinvigorate NEPA reviews and in March 2012, issued final guidance that may result in longer review processes.
Climate Change. In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted regulations under the Clean Air Act that, among other things, establish GHG emission limits from motor vehicles as well as establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. In October 2013, the U.S. Supreme Court agreed to hear a lawsuit challenging whether the

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EPA permissibly determined that the regulation of GHG emissions from new motor vehicles triggered permitting requirements under the Clean Air Act for stationary sources that emit GHGs, with a decision expected in 2014.
In addition, in September 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emitting sources in the United States beginning in 2011 for emissions in 2010. In November 2010, the EPA published a final rule expanding its existing greenhouse gas emissions reporting to include onshore and offshore oil and natural gas systems beginning in 2012. We are required to report under these rules for our assets that have greenhouse gas emissions above the reporting thresholds. The EPA continues to consider additional climate change requirements for the energy industry. Because regulation of greenhouse gas emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these greenhouse gas initiatives will impact our operations.
Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher greenhouse gas emitting energy sources, our products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. Conversely, to the extent that our products are competing with lower greenhouse gas emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on greenhouse gas emissions.

Employees
SMLP does not have any employees. All of the employees required to conduct and support its operations are employed by Summit Investments or its affiliates, but these individuals are sometimes referred to as our employees. The officers of our general partner manage our operations and activities. As of December 31, 2013, Summit Investments employed 215 people who provide direct, full-time support to our operations. None of our employees are covered by collective bargaining agreements, and we have never experienced any business interruption as a result of any labor disputes.

Availability of Reports
SMLP makes certain filings with the Securities and Exchange Commission (the "SEC"), including its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments and exhibits to those reports, available free of charge through its website, www.summitmidstream.com , as soon as reasonably practicable after the date they are filed with, or furnished to, the SEC. The filings are also available at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549 or by calling 1-800-SEC-0330. These filings are also available through the SEC's website, www.sec.gov . SMLP’s press releases and recent investor presentations are also available on SMLP’s website.

Item 1A. Risk Factors.
Risks Related to our Business
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution or any distribution to holders of our common and subordinated units.
To pay the minimum quarterly distribution of $0.40 per unit per quarter, or $1.60 per unit on an annualized basis, we will require available cash of approximately $21.9 million per quarter, or $87.8 million per year (based on units outstanding, as of December 31, 2013, including nonvested LTIP awards). We may not have sufficient available cash from operating surplus each quarter to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
the volume of natural gas we gather and compress;
the level of production of natural gas from wells connected to our gathering systems, which is dependent in part on the demand for, and the market prices of, crude oil, natural gas and NGLs;

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damage to pipelines, facilities, related equipment and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters, accidents and acts of terrorism;
leaks or accidental releases of hazardous materials into the environment, whether as a result of human error or otherwise;
weather conditions and seasonal trends;
changes in the fees we charge for our services;
the level of competition from other midstream energy companies in our geographic markets;
changes in the level of our operating, maintenance and general and administrative costs;
regulatory action affecting the supply of, or demand for, crude oil, natural gas and NGLs, the fees we can charge, how we contract for services, our existing contracts, our operating costs or our operating flexibility; and
prevailing economic and market conditions.
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
the level and timing of capital expenditures we make;
the level of our operating and general and administrative expenses, including reimbursements to our general partner for services provided to us;
the cost of acquisitions, if any;
our debt service requirements and other liabilities;
fluctuations in our working capital needs;
our ability to borrow funds and access capital markets;
restrictions contained in our debt agreements;
the amount of cash reserves established by our general partner; and
other business risks affecting our cash levels.
We depend on a relatively small number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, or the curtailment of production by, any one or more of these customers could materially adversely affect our revenues, cash flow and ability to make cash distributions to our unitholders.
A significant percentage of our revenue is attributable to a relatively small number of customers. If our customers curtail or reduce production in our areas of operation it could reduce throughput on our system and, therefore, materially adversely affect our revenues, cash flow and ability to make cash distributions to our unitholders.
Some of our customers may have material financial and liquidity issues or may, as a result of operational incidents or other events, be disproportionately affected as compared to larger, better-capitalized companies. Any material nonpayment or nonperformance by any of our key customers could have a material adverse effect on our revenue and cash flows and our ability to make cash distributions to our unitholders. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our revenue.
Due to our lack of industry and geographic diversification, adverse developments in our existing areas of operation could materially adversely impact our financial condition, results of operations and cash flows and reduce our ability to make cash distributions to our unitholders.
Our operations are focused on natural gas gathering and compression services in four unconventional resource basins: (i) the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia; (ii) the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; (iii) the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and (iv) the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado. As a result, our financial condition, results of operations and cash flows depend upon the demand for our services in these regions. Due to our lack of industry and geographic diversity, adverse developments in our current segment of

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the midstream industry or our existing areas of operation could have a significantly greater impact on our financial condition, results of operations and cash flows than if our operations were more diversified.
Our operations in the Barnett Shale region could expose us to disproportionate operational and regulatory risk in that area. The location of the Barnett Shale in the Dallas-Fort Worth, Texas metropolitan area poses unique challenges associated with drilling for and gathering natural gas in urban and suburban communities. The DFW Midstream system is within the city limits of various municipalities in that region, including Arlington, Texas. State and local regulations regarding the operation of drilling rigs limit the number of potential new drilling sites that can be used for infill drilling programs, which has led producers to pursue a high-density pad site drilling strategy. Furthermore, the process of obtaining permits for constructing additional gathering lines to deliver our customers' natural gas to market may be more time consuming and costly than in more rural areas. In addition, we may experience a higher rate of litigation or increased insurance and other costs related to our operations or facilities in such highly populated areas.
Significant prolonged weaknesses in natural gas prices could affect supply and demand, reducing throughput on our systems and materially adversely affecting our revenues and cash available to make cash distributions to our unitholders over the long-term.
Lower natural gas prices over the long term could result in a decline in the production of natural gas resulting in reduced throughput on our systems. The price of natural gas has been at historically low levels for an extended period of time. The lower price of natural gas is due in part to increased production, especially from unconventional sources, such as natural gas shale plays, high levels of natural gas in storage and the effects of the economic downturn starting in 2008. Furthermore, the amount of natural gas in storage in the continental United States has generally increased due to the decisions of many producers to store natural gas in the expectation of higher prices in the future as well as decreased demand as a result of unseasonably warm winters. In response to lower natural gas prices, the number of natural gas drilling rigs has declined as a number of producers have curtailed their exploration and production activities. Until the supply overhang has been reduced and the economy sees more robust growth, we believe that natural gas pricing is likely to be constrained.
The current level of low natural gas prices has had a negative impact on exploration, development and production activity in certain of our areas of operation, including the Fort Worth and Piceance basins. Due to the extended period of historically low natural gas prices, certain of our customers in those basins have announced their intent to reduce capital expenditures for dry gas drilling activities. For instance, in December 2013, Encana, one of our largest producers in the Piceance Basin, announced that they would cease drilling any additional natural gas wells in the Piceance Basin in 2014 in connection with their stated strategy to deploy additional capital resources to oil and liquids-rich basins.
If natural gas prices remain depressed or decrease further, it could cause sustained reductions in exploration or production activity in our areas of operation and result in a further reduction in throughput on our systems, which could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our unitholders.
Also, higher natural gas prices over the long term could result in a decline in the demand for natural gas and, therefore, in the throughput on our systems. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our unitholders.
Because of the natural decline in production from existing wells in our areas of operation, our success depends in part on our customers replacing declining production and also on our ability to maintain levels of throughput on our systems. Any decrease in the volumes of natural gas that we gather could materially adversely affect our business and operating results.
The natural gas volumes that support our business depend on the level of production from natural gas wells connected to our systems, the production from which may be less than expected and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on our systems, we must obtain new sources of natural gas. The primary factors affecting our ability to obtain new sources of natural gas include (i) the level of successful drilling activity in our areas of operation and (ii) our ability to compete for volumes from successful new wells.
We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling and production decisions, which are affected by, among other things:

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the availability and cost of capital;
prevailing and projected commodity prices, including the prices of crude oil, natural gas and NGLs;
demand for crude oil, natural gas and NGLs;
levels of reserves;
geological considerations;
environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and
the availability of drilling rigs and other costs of production and equipment.
Fluctuations in energy prices can also greatly affect the development of new crude oil and natural gas reserves. Drilling and production activity generally decreases as commodity prices decrease. In general terms, the prices of crude oil, natural gas, 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 ("LNG");
the ability to export LNG;
the availability of transportation systems with adequate capacity;
the volatility and uncertainty of regional pricing differentials and premiums;
the price and availability of alternative fuels;
the effect of energy conservation measures;
the nature and extent of governmental regulation and taxation; and
the anticipated future prices of crude oil, natural gas, LNG and other commodities.
Because of these factors, even if new crude oil or natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, those reductions could reduce our revenue and cash flow and materially adversely affect our ability to make cash distributions to our unitholders.
In addition, it may be more difficult to maintain or increase the current volumes on our gathering systems, as several of the formations in the unconventional resource plays in which we operate generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Should we determine that the economics of our gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, revenues associated with these assets will decline over time. In addition to capital expenditures to support growth, the steeper production decline curves associated with unconventional resource plays may require us to incur higher maintenance capital expenditures over time, which will reduce our cash available for distribution.
Many of our operating costs are fixed and do not vary with our throughput. These costs may not decline ratably or at all should we experience a reduction in throughput, which would result in a decline in our revenue and cash flow and materially adversely affect our ability to make cash distributions to our unitholders.
If our customers do not increase the volumes of natural gas they provide to our gathering systems, our growth strategy and ability to increase cash distributions to our unitholders may be materially adversely affected.
If we are unsuccessful in attracting new customers, our ability to increase the throughput on our gathering systems will be dependent on receiving increased volumes from our existing customers. Other than the scheduled increases in the minimum volume commitments provided for in our gas gathering agreements, our customers are not obligated to provide additional volumes to our systems, and they may determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. Reductions by our

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customers in our areas of mutual interest could result in reductions in throughput on our systems and materially adversely impact our ability to grow our operations and increase cash distributions to our unitholders.
Our gas gathering agreements contain provisions that can reduce the cash flow stability that the agreements were designed to achieve.
Our gas gathering agreements were designed to generate stable cash flows for us over the life of the minimum volume commitment contract term while also minimizing direct commodity price risk. Under these minimum volume commitments, our customers agree to ship a minimum volume of natural gas on our gathering systems or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the minimum volume commitment. In addition, the majority of our gas gathering agreements also include an aggregate minimum volume commitment, which is a total amount of natural gas that the customer must transport on our gathering system (or an equivalent monetary amount) over the minimum volume commitment term. If a customer's actual throughput volumes are less than its minimum volume commitment for the applicable period, it must make a shortfall payment to us at the end of that contract month or year, as applicable. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped for the applicable period and the minimum volume commitment for the applicable period, multiplied by the applicable gathering fee. To the extent that a customer's actual throughput volumes are above or below its minimum volume commitment for the applicable period, many of our gas gathering agreements contain provisions that allow the customer to use the excess volumes or the shortfall payment to credit against future excess volumes or future shortfall payments in subsequent periods. These provisions include the following:
To the extent that a customer's throughput volumes are less than its minimum volume commitment for the applicable period and the customer makes a shortfall payment, it may be entitled to an offset in one or more subsequent periods to the extent that its throughput volumes in subsequent periods exceed its minimum volume commitment for those periods. In such a situation, we would not receive gathering fees on throughput in excess of a customer's monthly or annual minimum volume commitment (depending on the terms of the specific gas gathering agreement) to the extent that the customer had made a shortfall payment with respect to one or more preceding months or years (as applicable).
To the extent that a customer's throughput volumes exceed its minimum volume commitment in the applicable period, it may be entitled to apply the excess throughput against its aggregate minimum volume commitment, thereby reducing the period for which its annual minimum volume commitment applies. For example, one of our DFW Midstream customers had a contracted minimum volume commitment term from October 2010 through September 2017. However, this customer regularly shipped volumes in excess of its minimum volume commitments and satisfied the requirements of its aggregate minimum volume commitment in less than three years. As a result of this mechanism, the weighted-average remaining period for which our minimum volume commitments apply is less than the weighted-average of the original stated terms of our minimum volume commitments.
To the extent that certain of our customers' throughput volumes exceed its MVC for the applicable period, there is a crediting mechanism that allows the customer to build a bank of credits that it can utilize in the future to reduce shortfall payments owed in subsequent periods, subject to expiration in the event that there is no shortfall in subsequent periods. The period over which this credit bank can be applied to future shortfall payments varies, depending on the particular gas gathering agreement. In such a situation, we would receive lower gathering fees in a particular contract year than we would otherwise be entitled to receive under the customer's minimum volume commitment.
Under certain circumstances, it is possible that the combined effect of the minimum volume commitment provisions could result in our receiving no revenues or cash flows from one or more customers in a given period. In the most extreme circumstances:
we could incur operating expenses with no corresponding revenues from one or more significant customers for a period of up to 35 months; or
all or a substantial portion of our customers could cease shipping throughput volumes at a time when their respective aggregate minimum volume commitments have been satisfied with previous throughput volume shipments.
If either of these circumstances were to occur, it would have a material adverse effect on our results of operations, financial condition and cash flows and our ability to make cash distributions to our unitholders.

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We do not intend to obtain independent evaluations of natural gas reserves connected to our gathering systems on a regular or ongoing basis; therefore, in the future, volumes of natural gas on our systems could be less than we anticipate.
We have not obtained and do not intend to obtain independent evaluations of the natural gas reserves connected to our systems on a regular or ongoing basis. Moreover, even if we did obtain independent evaluations of the natural gas reserves connected to our systems, such evaluations may prove to be incorrect. Crude oil and natural gas reserve engineering requires subjective estimates of underground accumulations of crude oil and natural gas and assumptions concerning future crude oil and natural gas prices, future production levels and operating and development costs.
Accordingly, we may not have accurate estimates of total reserves dedicated to some or all of our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering systems are less than we anticipate and we are unable to secure additional sources of natural gas, it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
Our industry is highly competitive, and increased competitive pressure could materially adversely affect our business and operating results.
We compete with other midstream companies in our areas of operation. Some of our competitors are large companies that have greater financial, managerial and other resources than we do. In addition, some of our competitors have assets in closer proximity to natural gas supplies and have available idle capacity in existing assets that would not require new capital investments for use. Our competitors may expand or construct natural gas gathering systems that would create additional competition for the services we provide to our customers. Because our customers do not have leases that cover the entirety of our areas of mutual interest, non-customer producers that lease acreage within any of our areas of mutual interest and produce natural gas may choose to use one of our competitors to gather that natural gas.
In addition, our customers may develop their own gathering systems outside of our areas of mutual interest. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flow could be materially adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
We may not be able to renew or replace expiring contracts at favorable rates or on a long-term basis.
We gather the natural gas on our systems under contracts with terms of various durations. As these contracts expire, we may have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. We may be unable to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. Moreover, we may be unable to obtain areas of mutual interest from new customers in the future, and we may be unable to renew existing areas of mutual interest with current customers as and when they expire. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:
the level of existing and new competition to provide gathering services to our markets;
the macroeconomic factors affecting natural gas gathering economics for our current and potential customers;
the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;
the extent to which the customers in our markets are willing to contract on a long-term basis; and
the effects of federal, state or local regulations on the contracting practices of our customers.
To the extent we are unable to renew our existing contracts on terms that are favorable to us or successfully manage our overall contract mix over time, our revenues and cash flows could decline and our ability to make cash distributions to our unitholders could be materially adversely affected.

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We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties, and any material nonpayment or nonperformance by one or more of these parties could materially adversely affect our financial and operating results.
Although we attempt to assess the creditworthiness of our customers, suppliers and contract counterparties, there can be no assurance that our assessments will be accurate or that there will not be a rapid or unanticipated deterioration in their creditworthiness, which may have an adverse impact on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. In addition, there can be no assurance that our contract counterparties will perform or adhere to existing or future contractual arrangements.
The policies and procedures we use to manage our exposure to credit risk, such as credit analysis, credit monitoring and, in some cases, requiring credit support, cannot fully eliminate counterparty credit risks. To the extent our policies and procedures prove to be inadequate, our financial and operational results may be negatively impacted.
Some of our counterparties may be highly leveraged or have limited financial resources and will be subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with such parties. In addition, volatility in commodity prices might have an impact on many of our counterparties, which, in turn, could have a negative impact on their ability to meet their obligations to us and may also increase the magnitude of these obligations.
Any material nonpayment or nonperformance by any of our counterparties could require us to pursue substitute counterparties for the affected operations, reduce our operations or seek out alternative service providers. There can be no assurance that any such efforts would be successful or would provide similar financial and operational results.
If third-party pipelines or other midstream facilities interconnected to our gathering systems become partially or fully unavailable, our revenue and cash flow and our ability to make cash distributions to our unitholders could be materially adversely affected.
Our natural gas gathering pipelines connect to other pipelines and midstream facilities, such as processing plants, owned and operated by unaffiliated third parties. The continuing operation of such third-party pipelines and other midstream facilities is not within our control. These pipelines and other midstream facilities may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from other operational hazards. For example, in the third quarter of 2013, volume throughput for the Mountaineer Midstream system was impacted by temporary processing capacity curtailments resulting from a line break on one of MarkWest’s NGL pipelines which forced the Mountaineer Midstream system to curtail its natural gas deliveries to MarkWest's Sherwood Processing Plant. In addition, we do not have interconnect agreements with all of these pipelines and other facilities and the agreements we do have may be terminated in certain circumstances and on short notice. If any of these pipelines or other midstream facilities become unavailable for any reason, or, if these third parties are otherwise unwilling to receive or transport the natural gas that we gather, our revenue, cash flow and ability to make cash distributions to our unitholders could be materially adversely affected.
We have a limited ownership history with respect to all of our assets, and we have owned Bison Midstream and Mountaineer Midstream for less than a full year. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with our pipelines that could have a material adverse effect on our business and operating results.
We purchased all of our assets in the last five years, and we have owned Bison Midstream and Mountaineer for less than one year. As a result, our executive management team has a relatively limited history of operating our assets. There may be historical occurrences or latent issues regarding our pipeline systems of which our executive management team may be unaware and that may have a material adverse effect on our business and results of operations. The steeper production decline curves associated with unconventional resource plays may require us to incur higher maintenance capital expenditures over time to connect additional wells and maintain throughput volume. Any significant increase in maintenance and repair expenditures or loss of revenue due to the condition of our pipeline systems could materially adversely affect our business and results of operations and our ability to make cash distributions to our unitholders.

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A shortage of skilled labor in the midstream natural gas industry could reduce employee productivity and increase costs, which could have a material adverse effect on our business and results of operations.
The gathering of natural gas requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. We have from time to time encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially adversely affected. If our labor prices increase or if we experience materially increased health and benefit costs with respect to our general partner's employees, our business and results of operations and our ability to make cash distributions to our unitholders could be materially adversely affected.
Crude oil and natural gas activities in certain areas of our gathering systems may be adversely affected by seasonal weather conditions which in turn could negatively impact the operations of our gathering facilities and our construction of additional facilities.
Extended periods of below freezing weather and unseasonably wet weather conditions across our systems, especially in North Dakota and West Virginia, can be severe and can adversely affect oil and gas operations due to the potential shut-in of producing wells or decreased drilling activities. The result of these types of interruptions could result in a decrease in the volumes of natural gas supplied to our gathering systems. Further, delays and shutdowns caused by severe weather during the winter months may have a material negative impact on the continuous operations of our gathering systems, including interruptions in service. These types of interruptions could negatively impact our ability to meet contractual obligations to our customers and thereby give rise to certain termination rights and releases of dedicated acreage. Any resulting terminations or releases could materially affect our business and results of operations.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not adequately insured or if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, our operations and financial results could be materially adversely affected.
Our operations are subject to all of the risks and hazards inherent in the gathering, compressing and dehydrating of natural gas, including:
damage to pipelines and plants, related equipment and surrounding properties caused by tornadoes, floods, fires and other natural disasters and acts of terrorism;
inadvertent damage from construction, vehicles, farm and utility equipment;
leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities;
ruptures, fires and explosions; and
other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. The location of certain of our systems in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from these risks.
These risks may also result in curtailment or suspension of our operations. A natural disaster or any event such as those described above affecting the areas in which we and our customers operate could have a material adverse effect on our operations. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segments of our systems. Potential customer impacts arising from service interruptions on segments of our systems could include limitations on our ability to satisfy customer requirements, obligations to temporarily waive minimum volume commitments to customers during times of constrained capacity, and solicitation of existing customers by others for potential new projects that would compete directly with our existing services. Such circumstances could materially adversely impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business and results of operations and our ability to make cash distributions to our unitholders.
Although we have a range of insurance programs providing varying levels of protection for public liability, damage to property, loss of income and certain environmental hazards, we may not be insured against all causes of loss, claims or damage that may occur. If a significant accident or event occurs for which we are not fully insured, it could

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materially adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, with regard to the assets we have acquired, we have limited indemnification rights to recover for potential environmental liabilities.
We intend to grow our business in part by seeking strategic acquisition opportunities. If we are unable to make acquisitions on economically acceptable terms from SMP Holdings or third parties, our future growth will be affected, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per-unit basis.
Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per-unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants. A material decrease in such divestitures would limit our opportunities for future acquisitions and could materially adversely affect our ability to grow our operations and increase our cash distributions to our unitholders.
If we are unable to make accretive acquisitions from SMP Holdings or third parties, whether because we are (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts; (ii) unable to obtain financing for these acquisitions on economically acceptable terms; (iii) outbid by competitors; or (iv) unable to obtain necessary governmental or third-party consents or for any other reason, then our future growth and ability to increase cash distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per-unit basis.
Any acquisition, including the acquisitions of Bison Midstream and Mountaineer Midstream, involves potential risks, including, among other things:
mistaken assumptions about volumes, revenue and costs, including synergies and potential growth;
an inability to secure adequate customer commitments to use the acquired systems or facilities;
the risk that natural gas or crude oil reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;
an inability to integrate successfully the assets or businesses we acquire;
coordinating geographically disparate organizations, systems and facilities;
the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;
mistaken assumptions about the overall costs of equity or debt;
the diversion of management's and employees' attention from other business concerns;
unforeseen difficulties operating in new geographic areas and business lines;
customer or key employee losses at the acquired businesses; and
production declines higher than anticipated and facilities being properly constructed.
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.
We may fail to successfully integrate Bison Midstream and Mountaineer Midstream into our existing business in a timely manner, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders, or fail to realize all of the expected benefits of the acquisitions, which could negatively impact our future results of operations.
Integration of the assets acquired in the Bison Midstream and Mountaineer Midstream acquisitions with our existing business has been, and will be, a complex, time-consuming and costly process, particularly given that the acquired assets significantly increased our size and diversified the geographic areas in which we operate. A failure to successfully integrate the acquired assets with our existing business in a timely manner may have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

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If any of the risks described in the risk factor immediately above or unanticipated liabilities or costs were to materialize with respect to the Bison Midstream or Mountaineer Midstream acquisitions, or if the acquired assets were to perform at levels below the forecasts we used to evaluate them, then the anticipated benefits from the acquisition may not be fully realized, if at all, and our future results of operations could be negatively impacted.
Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could materially adversely affect our results of operations and financial condition.
One of the ways we intend to grow our business is through organic growth projects. For example, in November 2013, we announced an amendment of our natural gas gathering agreement with Antero Resources Corporation (“Antero”) related to the development of a new high-pressure pipeline looping project designed to expand throughput capacity at Mountaineer Midstream to 1,050 MMcf/d (the “Zinnia Loop”). The Zinnia Loop is being constructed to support an anticipated increase in throughput related to Antero’s drilling program in the Marcellus Shale formation. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control.
Such expansion projects may also require the expenditure of significant amounts of capital, and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, our revenue may not increase immediately upon the expenditure of funds on a particular project.
For instance, as we develop the Zinnia Loop project to support Antero’s drilling program in the Marcellus Shale formation, the construction will occur over an extended period of time, yet we will not receive any material increases in revenue until the project is completed and placed into service. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize or only materializes over a period materially longer than expected. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate as a result of the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not attract enough throughput to achieve our expected investment return, which could materially adversely affect our results of operations and financial condition.
In addition, the construction of additions or modifications to our existing gathering assets and the construction of new midstream assets may require us to obtain new rights-of-way or federal and state environmental or other authorizations. The approval process for gathering activities has become increasingly challenging, due in part to state and local concerns related to unregulated exploration and production and gathering activities in new production areas. Such authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions. As a result, we may be unable to obtain such rights-of-way or other authorizations and may, therefore, be unable to connect new natural gas volumes to our systems or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or authorizations or to renew existing rights-of-way or authorizations. If the cost of renewing or obtaining new rights-of-way or authorizations increases materially, our cash flows could be materially adversely affected.
We require access to significant amounts of additional capital to implement our growth strategy, as well as to meet potential future capital requirements under certain of our gas gathering agreements. Tightened capital markets could impair our ability to grow or cause us to be unable to meet future capital requirements.
To expand our asset base, whether through acquisitions or organic growth, we will need to make expansion capital expenditures. We also frequently consider and enter into discussions with third parties regarding potential acquisitions. In addition, the terms of certain of our gas gathering agreements also require us to spend significant amounts of capital, including over a short period of time, to construct and develop additional midstream assets to support our customers' development projects. Depending on our customers' future development plans, it is possible that the capital we would be required to spend to construct and develop such assets could exceed our ability to finance those expenditures using our cash reserves or available capacity under our amended and restated revolving credit facility.
We plan to use cash from operations, incur borrowings, and/or sell additional common units or other securities to fund our future expansion capital expenditures. Using cash from operations to fund expansion capital expenditures will directly reduce our cash available for distribution to unitholders. Our ability to obtain financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such

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financing or offering as well as covenants in our debt agreements, general economic conditions and contingencies and uncertainties that are beyond our control. If we are unable to raise expansion capital, we may lose the opportunity to make acquisitions or to gather new natural gas production from our customers with whom we have agreed to construct and develop midstream assets in the future. Even if we are successful in obtaining funds for expansion capital expenditures through equity or debt financings, the terms thereof could limit our ability to pay distributions to our common unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional units representing limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.
We do not have any commitment from our Sponsors or their affiliates to provide any direct or indirect financial assistance to us.
Because our common units are yield-oriented securities, increases in interest rates could materially adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions to our unitholders.
Interest rates are generally at or near historic lows and may increase in the future. As a result, interest rates on our future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase. 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 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 a material adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.
At December 31, 2013, we had $586.0 million of total indebtedness and the unused portion of our $700.0 million amended and restated revolving credit facility totaled $414.0 million. Our future level of debt could have significant consequences, including the following:
our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
our funds available for operations, future business opportunities and cash distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;
we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
our flexibility in responding to changing business and economic conditions may be limited.
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.
Restrictions in our amended and restated revolving credit facility and senior notes indenture could materially adversely affect our business, financial condition, results of operations, ability to make cash distributions to unitholders and value of our common units.
We are dependent upon the earnings and cash flow generated by our operations in order to meet our debt service obligations and to make cash distributions to our unitholders. The operating and financial restrictions and covenants in our amended and restated revolving credit facility, our indenture and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make cash distributions to our unitholders. For example, our amended and restated revolving credit facility and indenture restrict our ability to, among other things:
incur or guarantee additional debt;

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make cash distributions on or redeem or repurchase units;
make certain investments and acquisitions;
make capital expenditures;
incur certain liens or permit them to exist;
enter into certain types of transactions with affiliates;
merge or consolidate with another company or otherwise engage in a change of control; and
transfer, sell or otherwise dispose of assets.
Our amended and restated revolving credit facility and indenture also contain covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot guarantee that we will meet those ratios and tests.
The provisions of our amended and restated revolving credit facility and indenture may affect our ability to obtain future financing and pursue attractive business opportunities as well as affect our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our amended and restated revolving credit facility or indenture could result in a default or an event of default that could enable our lenders or noteholders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If we were unable to repay the accelerated amounts, the lenders under our amended and restated revolving credit facility could proceed against the collateral granted to them to secure such debt. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. The amended and restated revolving credit facility also has cross default provisions that apply to any other indebtedness we may have and the indentures have cross default provisions that apply to certain other indebtedness.
A portion of our revenues are exposed to changes in crude oil and natural gas prices, and our exposure may increase in the future.
We generate a substantial majority of our revenues pursuant to long-term, primarily fee-based gas gathering agreements under which we are paid based on the volumes of natural gas that we gather rather than the value of the underlying natural gas. Consequently, our existing operations and cash flows have limited direct exposure to commodity price risk. Although we will seek to enter into similar fee-based contracts with new customers in the future, our efforts to obtain such contractual terms may not be successful or the local market for our services may not support fee-based gas gathering agreements. For example, in connection with our acquisition of Bison Midstream, we have percent-of-proceeds contracts with certain customers and we may, in the future, enter into additional percent-of-proceeds contracts with our customers, which would increase our exposure to commodity price risk, as the revenues generated from those contracts directly correlate with the fluctuating price of natural gas and natural gas liquids.
Substantially all of our remaining revenue is derived from (i) the sale of physical natural gas that we retain from our DFW Midstream customers to offset our power expense associated with our electric-drive compression and (ii) the sale of condensate volumes that we collect on the Grand River system. The revenues we earn from the sale of retained natural gas are tied to the price of natural gas. In addition, changes in the price of crude oil could directly affect the revenues we receive from the sale of condensate.
Furthermore, we may acquire or develop additional midstream assets in the future, including assets related to commodities other than natural gas, that have a greater exposure to fluctuations in commodity price risk than our current operations. Future exposure to the volatility of crude oil and natural gas prices could have a material adverse effect on our business, results of operations and financial condition.
A change in laws and regulations applicable to our assets or services, or the interpretation or implementation of existing laws and regulations may cause our revenue to decline or our operating and maintenance expenses to increase.
Various aspects of our operations are subject to extensive regulation. Numerous federal, state and local departments and agencies are authorized by statute to issue, and have issued, rules, regulations and interpretations binding upon participants in the natural gas industry. The regulation of our activities and the natural gas industry generally frequently changes as the activities of the industry often are reviewed by legislators and regulators. In 2014, the North Dakota Industrial Commission will begin to oversee the integrity and location of underground gathering pipelines that are not monitored by other state or federal agencies. The U.S. Department of

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Transportation (DOT) is considering rule changes that would extend pipeline safety regulation to previously unregulated rural gathering systems and increase safety requirements for other pipelines as well. Penalties for violating federal safety standards have recently increased. In addition, the adoption of proposals for more stringent legislation, regulation or taxation of natural gas drilling activity could directly curtail such activity or increase the cost of drilling, resulting in reduced levels of drilling activity and therefore reduced demand for our services. Regulatory agencies establish and from time to time change priorities, which may result in additional burdens on us, such as additional reporting requirements and more frequent audits of operations. Our operations and the markets in which we participate are affected by these laws, regulations and interpretations and may be affected by changes to them or their implementation, which may cause us to realize materially lower revenues or incur materially increased operating costs or both.
Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could materially adversely impact our revenues.
A substantial majority of our customers' crude oil and natural gas production is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate crude oil and natural gas production. We do not engage in any hydraulic fracturing activities although many of our customers do. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of underground injection and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of the U.S. Congress. Congress will likely continue to consider legislation to amend the Safe Drinking Water Act to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Any such legislation could make it easier for third parties opposed to hydraulic fracturing to initiate legal proceedings against our customers.
Scrutiny of hydraulic fracturing activities continues in other ways, with both regulatory and study initiatives. For example, in May 2012, the Bureau of Land Management issued a proposed rule to regulate hydraulic fracturing on public and Indian lands. The proposed rule would require public disclosure of chemicals used in hydraulic fracturing on federal and Indian lands, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. The final rule has not yet been published, but is expected sometime in 2014. In addition, the EPA has commenced a multi-year study of the potential environmental impacts of hydraulic fracturing, and a draft report of the findings is expected in 2014. Similarly, in October 2011, the EPA announced its intention to propose regulations by 2014 under the federal Clean Water Act to develop standards for wastewater discharges from hydraulic fracturing and other natural gas production activities.
Depending on the outcome of these studies and other initiatives, federal and state legislatures and agencies may seek to further regulate hydraulic fracturing activities.
Several states, including Texas, Colorado, North Dakota and West Virginia, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing through additional permit requirements, public disclosure of fracturing fluid contents, operational restrictions, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. We cannot predict whether any other legislation will be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs and prohibitions for producers who drill near our pipelines which could reduce the volumes of natural gas available to move through our gathering systems, and thus materially adversely affect our revenue and results of operations and ability to make cash distributions.
In April 2012, the EPA approved final rules that would subject all oil and natural gas operations (production, processing, transmission, storage and distribution) to regulation under the NSPS and National Emission Standards for Hazardous Air Pollutants programs. These rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completion techniques developed in the EPA's Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under the National Emission Standards for Hazardous Air Pollutants program include maximum achievable control technology standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to maximum achievable control technology standards. At this point, the effect these proposed rules could have on our business has not been determined. While these rules have been

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finalized, many of the rules' provisions will be phased in over time, with the more stringent requirements like reduced emission completion not becoming effective until 2015.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to increased operating costs in the production of crude oil and natural gas, or could make it more difficult to perform hydraulic fracturing, either of which could have an adverse effect on our customers. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new crude oil and natural gas wells, increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows.
We are subject to federal anti-market manipulation laws and regulations, potentially other federal regulatory requirements, and state and local regulation, and could be materially affected by changes in such laws and regulations, or in the way they are interpreted and enforced.
We believe that our pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of FERC, the NGA and the NGPA. We are, however, subject to the anti-market manipulation provisions in the NGA, as amended by the Energy Policy Act of 2005, and to FERC's regulations thereunder, which authorize FERC to impose fines of up to $1,000,000 per day per violation of the NGA or its implementing regulations. In addition, the Federal Trade Commission holds statutory authority under the Energy Independence and Security Act of 2007 to prevent market manipulation in oil markets, and has adopted broad rules and regulations prohibiting fraud and market manipulation. The Federal Trade Commission is also authorized to seek fines of up to $1,000,000 per violation. The Commodity Futures Trading Commission (the "CFTC") is directed under the Commodity Exchange Act, to prevent price manipulation in the commodity, futures and swaps markets, including the energy markets. Pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, also known as the Dodd-Frank Act, and other authority, the CFTC has adopted additional anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity, futures and swaps markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1,000,000 per violation or triple the monetary gain to the violator for each violation of the anti-market manipulation provisions of the Commodity Exchange Act.
The distinction between federally unregulated gathering facilities and FERC-regulated transmission pipelines has been the subject of extensive litigation and is determined by FERC on a case-by-case basis, although FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of some of our pipelines could change based on future determinations by FERC, Congress or the courts. If our gas gathering operations become subject to FERC jurisdiction over interstate service under the NGA or the Natural Gas Policy Act of 1978, or NGPA, the result may materially adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by the FERC.
We are subject to state and local regulation regarding the construction and operation of our gathering systems, as well as state ratable take statutes and regulations. Regulation of the construction and operation of our facilities may affect our ability to expand our facilities or build new facilities and such regulation may cause us to incur additional operating costs or limit the quantities of gas we may gather. Ratable take statutes and regulations generally require gatherers to take natural gas production that may be tendered for gathering without undue discrimination. These requirements restrict our right to decide whose production we gather. Many states have adopted complaint-based regulation of gathering activities, which allows producers and shippers to file complaints with state regulators in an effort to resolve access issues, rate grievances, and other matters. Other state and municipal regulations do not directly apply to our business, but may nonetheless affect the availability of natural gas for gathering, including state regulation of production rates, maximum daily production allowable from natural gas wells, and other activities related to drilling and operating wells. While our facilities currently are subject to limited state and local regulation, there is a risk that state or local laws will be changed or reinterpreted, which may materially affect our operations, operating costs, and revenues.
We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.
Our natural gas gathering, compression and dehydrating operations are subject to stringent and complex federal, state and local environmental laws and regulations, including laws and regulations regarding the discharge of materials into the environment or otherwise relating to environmental protection. Examples of these laws include:

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the federal Clean Air Act and analogous state laws that impose obligations related to air emissions;
the federal Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or the Superfund law, and analogous state laws that regulate the cleanup of hazardous substances that may be or have been released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal;
the federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws that regulate discharges from our facilities into state and federal waters, including wetlands;
the federal Oil Pollution Act and analogous state laws that establish strict liability for releases of oil into waters of the United States;
the federal Resource Conservation and Recovery Act and analogous state laws that impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities;
the Endangered Species Act; and
the Toxic Substances Control Act, and analogous state laws that impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.
These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations or at locations currently or previously owned or operated by us. 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 corrective actions or costly pollution control measures. Failure to comply with these laws, regulations and requisite permits may result in the assessment of significant administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue.
There is a risk that we may incur significant environmental costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of hydrocarbons and other wastes and potential emissions and discharges related to our operations. Joint and several, strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbon wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the properties through which our gathering systems pass and facilities where our wastes 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 and regulations or for personal injury or property damage. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. In addition, changes in environmental laws occur frequently, and any such changes that result in additional permitting obligations or more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. We may not be able to recover all or any of these costs from insurance.
We may incur greater than anticipated costs and liabilities as a result of pipeline safety requirements.
The U.S. Department of Transportation, through its Pipeline and Hazardous Materials Safety Administration, has adopted and enforces safety standards and procedures applicable to our pipelines. In addition, many states, including the states in which we operate, have adopted regulations that are identical to or more restrictive than existing U.S. DOT regulations for intrastate pipelines. Among the regulations applicable to us, the PHMSA requires pipeline operators to develop integrity management programs for certain pipelines located in high consequence areas, which include high population areas such as the Dallas-Fort Worth greater metropolitan area where our DFW Midstream system is located. While the majority of our pipelines meet the U.S. DOT definition of gathering lines and are thus exempt from the PHMSA's integrity management requirements, we also operate a limited number of pipelines that are subject to the integrity management requirements. The regulations require operators, including us, to:

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perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
maintain processes for data collection, integration and analysis;
repair and remediate pipelines as necessary;
adopt and maintain procedures, standards and training programs for control room operations; and
implement preventive and mitigating actions.
The PHMSA is considering changes to its safety regulations, including whether to revise the integrity management requirements and whether to change the definition of gathering pipelines, which could subject many currently exempted pipelines to PHMSA regulations and could have a material adverse effect on our operations and costs of transportation services. The PHMSA has also issued an Advisory Bulletin which, among other things, advises pipeline operators that if they are relying on design, construction, inspection, testing or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities to meet the demands of such pressures, could significantly increase our costs. Additionally, failure to locate such records or verify maximum pressures could result in reductions of allowable operating pressures, which would reduce available capacity of our pipelines. While we believe that we are in compliance with existing safety laws and regulations, increased penalties for safety violations and potential regulatory changes could have a material adverse effect on our operations, operating and maintenance expenses, and revenues.

Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the natural gas services we provide.
In recent years, the U.S. Congress has considered legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane that may be contributing to global warming. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other initiatives are expected to be proposed that may be relevant to greenhouse gas emissions issues. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address greenhouse gas emissions, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. In general, the number of allowances available for purchase is reduced each year until the overall greenhouse gas emission reduction goal is achieved. Depending on the scope of a particular program, we could be required to purchase and surrender allowances for greenhouse gas emissions resulting from our operations (e.g., at compressor stations). Although most of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions, such as electric power plants, it is possible that our sources, such as our gas-fired compressors, could become subject to state-level greenhouse gas-related regulation. Depending on the particular program, we may be required to control emissions or to purchase and surrender allowances for greenhouse gas emissions resulting from our operations.
Independent of Congress, the EPA has begun to adopt federal-level regulations controlling greenhouse gas emissions under its existing Clean Air Act authority. In 2009, the EPA issued required findings under the Clean Air Act concluding that emissions of greenhouse gases present an endangerment to human health and the environment, and issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emitting sources in the United States beginning in 2011 for emissions occurring in 2010. In May 2010, the EPA issued a final rule, known as the Tailoring Rule, that makes certain large stationary sources and modification projects subject to permitting requirements for greenhouse gas emissions under the Clean Air Act. In November 2010, the EPA issued a final rule expanding its existing greenhouse gas emissions reporting rule to include onshore and offshore oil and natural gas systems. These rules require data collection beginning in 2011 and reporting beginning in September 2012 and require that we report our greenhouse gas emissions for our assets that have greenhouse gas emissions above the reporting thresholds. As a result of this continued regulatory focus, further greenhouse gas regulation of the oil and gas industry remains a possibility.
On May 21, 2013, the Texas Legislature passed H.B. 788 which is intended to streamline GHG permitting in Texas by directing the Texas Commission on Environmental Quality ("TCEQ") to promulgate rules to be approved by the EPA that would replace EPA permitting of GHGs in Texas with TCEQ permitting. The bill was signed by the

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Governor on June 14, 2013 and is effective. TCEQ proposed regulations to implement H.B. 788 on October 23, 2013, a public hearing on these proposed regulations was held on December 5, 2013, and comments on the proposal were due on December 9, 2013. Depending on how and when TCEQ finalizes its proposed regulations implementing H.B. 788, TCEQ could impose additional requirements on our operations that could increase our operating costs.
Although it is not possible at this time to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business, either directly or indirectly, any future federal or state laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could materially adversely affect demand for the natural gas we gather or otherwise handle in connection with our services. The potential increase in the costs of our operations resulting from any legislation or regulation to restrict emissions of greenhouse gases could include new or increased costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. While we may be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities, such recovery of costs is uncertain. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for natural gas, resulting in a decrease in demand for our services. We cannot predict with any certainty at this time how these possibilities may affect our operations.
The adoption and implementation of new statutory and regulatory requirements for swap transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.
Congress adopted comprehensive financial reform legislation under the Dodd-Frank Act that establishes federal oversight and regulation of the over-the-counter, or OTC, derivatives market and entities, such as us, that participate in that market. This legislation requires the CFTC and the SEC and other regulatory authorities to promulgate certain rules and regulations, including rules and regulations relating to the regulation of certain swaps entities, the clearing of certain swaps through central counterparties, the execution of certain swaps on designated contract markets or swap execution facilities, and the reporting and recordkeeping of swaps. While certain regulations have been promulgated and are already in effect, the rulemaking and implementation process is still ongoing, and we cannot yet predict the ultimate effect of the rules and regulations on our business.
The CFTC has previously established position limits on certain core futures and equivalent swaps contracts in the major energy, including natural gas, and other markets, with exceptions for certain bona fide hedging transactions. The CFTC’s original position limits rules were vacated by a federal district court on September 28, 2012. On November 5, 2013, the CFTC proposed a new rulemaking on position limits and aggregation; however, it is uncertain at this time whether, when, and to what extent the CFTC’s position limits rules will become final and effective.
In December 2012, the CFTC published final rules regarding mandatory clearing of certain classes of interest rate swaps and certain classes of index credit default swaps and setting compliance dates of March 11, 2013, June 10, 2013, and, for commercial end users of swaps, September 9, 2013. At this time, the CFTC has not proposed any rules designating other classes of swaps, including physical commodity swaps, for mandatory clearing. Although we may qualify for the end-user exception from the mandatory clearing and trade execution requirements for our swaps entered into to hedge commercial risks, mandatory clearing and trade execution requirements applicable to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, for uncleared swaps, the CFTC or federal banking regulatory authorities may require our counterparties to require that we enter into credit support documentation and/or post margin as collateral; however, the proposed margin rules are not yet final and therefore the application of those rules to us is uncertain at this time.
We currently receive a fuel retainage fee from certain of our customers that is paid in-kind to offset the costs we incur to operate our electric-drive compression assets in the Barnett Shale. We currently enter into forward contracts with third parties to buy power and sell natural gas in an attempt to hedge our exposure to fluctuations in the price of natural gas with respect to those volumes. The impact of the Dodd-Frank Act on our hedging activities is uncertain at this time. However, the new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. The Dodd-Frank Act may also materially affect our customers and materially and adversely affect the demand for our services.

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We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
We do not own all of the land on which our pipelines and facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate or if our pipelines are not properly located within the boundaries of such rights-of-way. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. If we were to be unsuccessful in renegotiated rights-of-way, we might have to relocate our facilities. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of war could have a material adverse effect on our business, financial condition or results of operations.
Terrorist attacks and threats, escalation of military activity or acts of war may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. Disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.
Our operations depend on the use of information technology ("IT") systems that could be the target of a cyber-attack.
Our operations depend on the use of sophisticated IT systems. Our IT systems and networks, as well as those of our customers, vendors and counterparties, may become the target of cyber-attacks or information security breaches, which in turn could result in the unauthorized release and misuse of confidential or proprietary information as well as disrupt our operations or damage our facilities or those of third parties, which could have a material adverse effect on our revenues and increase our operating and capital costs, which could reduce the amount of cash otherwise available for distribution. We may be required to incur additional costs to modify or enhance our systems or in order to try to prevent or remediate any such attacks.
Our ability to operate our business effectively could be impaired if we fail to attract and retain key management personnel.
Our ability to operate our business and implement our strategies will depend on our continued ability to attract and retain highly skilled management personnel with midstream natural gas industry experience and competition for these persons in the midstream natural gas industry is intense. Given our size, we may be at a disadvantage, relative to our larger competitors, in the competition for these personnel. We may not be able to continue to employ our senior executives and key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract our senior executives and key personnel could have a material adverse effect on our ability to effectively operate our business.
If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results timely and accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.
As a publicly traded partnership, we are subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, including the rules thereunder that will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Effective internal controls are necessary for us to provide reliable and timely financial reports, prevent fraud and to operate successfully as a publicly traded partnership. We prepare our consolidated financial statements in accordance with generally accepted accounting principles, but our internal accounting controls may not meet all standards applicable to companies with publicly traded securities. Our efforts to develop and maintain our internal controls may not be successful and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002.
Given the difficulties inherent in the design and operation of internal controls over financial reporting, in addition to our limited accounting personnel and management resources, we can provide no assurance as to our or our

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independent registered public accounting firm's future conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to implement and maintain effective internal controls over financial reporting will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.
Although management is required to assess our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, our independent registered public accounting firm will not be required to formally attest to the effectiveness of our internal control over financial reporting until we are no longer an emerging growth company.
The amount of cash we have available for distribution to holders of our common and subordinated units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

Risks Inherent in an Investment in Us
Summit Investments, through its ownership of SMP Holdings, indirectly owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations as well as limited duties to us and our unitholders. Our general partner and its affiliates, including Summit Investments and SMP Holdings, have conflicts of interest with us and they may favor their own interests to the detriment of us and our unitholders.
SMP Holdings, which is owned and controlled by Summit Investments, controls our general partner, and has authority to appoint all of the officers and directors of our general partner, some of whom will also be officers, directors or principals of Energy Capital Partners, one of the two entities that own Summit Investments. Although our general partner has a duty to manage us in a manner that is in our best interests, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is in the best interests of its owner, SMP Holdings. Conflicts of interest will arise between SMP Holdings, Summit Investments, and its owners and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of SMP Holdings and Summit Investments and its owners 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 SMP Holdings or Summit Investments or its owners to pursue a business strategy that favors us, and the directors and officers of Summit Investments have a fiduciary duty to make these decisions in the best interests of the owners of Summit Investments, which may be contrary to our interests. SMP Holdings or Summit Investments may choose to shift the focus of their investment and growth to areas not served by our assets.
SMP Holdings and Summit Investments are not limited in their ability to compete with us and may offer business opportunities or sell midstream assets to third parties without first offering us the right to bid for them.
Our general partner is allowed to take into account the interests of parties other than us, such as SMP Holdings and Summit Investments and their owners, in resolving conflicts of interest.
Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner to us and our unitholders with contractual standards governing its duties to us and our unitholders. These contractual standards limit our general partner's liabilities and the rights of our unitholders with respect to actions that, without the limitations, might constitute breaches of fiduciary duty.
Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership interests and the creation, reduction or increase 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 expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert to common units.
Our general partner determines which costs incurred by it are reimbursable by us.
Our general partner may cause us to borrow funds to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.
Our partnership agreement permits us to classify up to $50.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights.
Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.
Our general partner intends to limit its liability regarding our contractual and other obligations.
Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.
Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner's incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our other unitholders in certain situations.
Our Sponsors are not limited in their ability to compete with us and are not obligated to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could materially adversely affect our results of operations and cash available for distribution to our unitholders.
Energy Capital Partners and GE Energy Financial Services have significantly greater resources than us and have experience making investments in midstream energy businesses. Energy Capital Partners and GE Energy Financial Services may compete with us for investment opportunities and may own interests in entities that compete with us. Energy Capital Partners and GE Energy Financial Services are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. For example, GE Energy Financial Services owns an interest in another midstream publicly traded partnership. In addition, in the future, Energy Capital Partners or GE Energy Financial Services may acquire, construct or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities. For example, in October 2012, Summit Investments acquired a natural gas gathering and processing system in the Piceance and Uinta basins in Colorado and Utah from a third party. In January 2014, Summit Investments acquired an interest in two entities (collectively, “Ohio Gathering”), that own, operate and are developing significant midstream infrastructure in southeastern Ohio consisting of a liquids-rich natural gas gathering system, a dry natural gas gathering system and a condensate transportation, storage and stabilization facility in the core of the Utica Shale.
While Summit Investments has indicated that it intends to offer us the opportunity to acquire its interests in Ohio Gathering, it is not under any contractual obligation to do so and we are unable to predict whether or when such opportunities may arise.
Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner, its officers and directors or any of its affiliates, including our Sponsors and their respective executive officers, directors and principals. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity

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pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.
The market price of our common units may fluctuate significantly and, due to limited daily trading volumes, an investor could lose all or part of its investment in us.
There were 14,388,469 publicly traded common units at December 31, 2013. In addition, SMP Holdings, which controls our general partner, owned 14,691,397 common and 24,409,850 subordinated units. An investor may not be able to resell its common units at or above its acquisition price. Additionally, a lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.
The market price of our common units may decline and 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;
the loss of a large customer;
announcements by us or our competitors of significant contracts or acquisitions;
changes in accounting standards, policies, guidance, interpretations or principles;
general economic conditions;
the failure of securities analysts to cover our common units or changes in financial estimates by analysts;
future sales of our common units; and
other factors described in these Risk Factors.
Our partnership agreement replaces our general partner's fiduciary duties to holders of our common and subordinated units with contractual standards governing its duties.
Our partnership agreement contains provisions that eliminate fiduciary duties to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner or otherwise, free of any duties to us and our unitholders, other than the implied contractual covenant of good faith and fair dealing. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:
how to allocate corporate opportunities among us and its affiliates;
whether to exercise its limited call right;
whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;
how to exercise its voting rights with respect to the units it owns;
whether to exercise its registration rights;
whether to elect to reset target distribution levels;
whether to transfer the incentive distribution rights or any units it owns to a third party; and
whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.
By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above.

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Our partnership agreement limits the liabilities of our general partner and the rights of our unitholders with respect to actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that limit the liability of our general partner and the rights of our unitholders with respect to 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 makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in our best interests, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;
our general partner and its officers and directors will not be liable for monetary damages to us, 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
our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:
(i)
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;
(ii)
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;
(iii)
on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
(iv)
fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the final two subclauses above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner's fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

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In addition, because we intend to distribute all of our available cash, we may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per-unit distribution level. There are no limitations in our partnership agreement or our amended and restated revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.
While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended.
While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by affiliates of our general partner) after the subordination period has ended. As of December 31, 2013, SMP Holdings, which owns and controls our general partner, owned 14,691,397 common units and 24,409,850 subordinated units.
Reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our common unitholders. The amount and timing of such reimbursements will be determined by our general partner.
Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including SMP Holdings and Summit Investments, for expenses they incur and payments they make on our behalf. Under our partnership agreement, we will reimburse our general partner and its affiliates for certain expenses incurred on our behalf, including administrative costs, such as compensation expense for those persons who provide services necessary to run our business. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our unitholders.
Our general partner may elect to cause us to issue common units to it in connection with a resetting of the minimum quarterly distribution and the target distribution levels related to our general partner's incentive distribution rights without the approval of the conflicts committee of our general partner's board or our unitholders. This election may result in lower distributions to our unitholders in certain situations.
Our general partner has the right, 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 (48.0%) for each of the prior four consecutive fiscal quarters (and the amount of each such distribution did not exceed adjusted operating surplus for such quarter), to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the reset minimum quarterly distribution), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
In the event of a reset of target distribution levels, our general partner will be entitled to receive the number of common units equal to that number of common units that would have entitled it to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions on the incentive distribution rights in the prior two quarters. Our general partner will also be issued the number of general partner units necessary to maintain its general partner interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive

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incentive distribution payments based on target distribution levels that are less certain to be achieved in the then-current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels related to our general partner's incentive distribution rights.
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
Unlike the holders of common stock in a corporation, holders of our common units have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner will be chosen by Summit Investments, in its capacity as sole member of SMP Holdings. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.
Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.
The unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2 / 3 % of all outstanding limited partner units voting together as a single class is required to remove our general partner. As of December 31, 2013, SMP Holdings, which controls our general partner, owned 14,691,397 common units out of 29,079,866 outstanding common units and all of our 24,409,850 subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would materially adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholder's dissatisfaction with our general partner's performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Unitholders' voting rights are further restricted by a provision of our partnership agreement providing that any person or group that owns 20% or more of any class of units then outstanding cannot vote on any matter, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner.
Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of SMP Holdings to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers. This effectively permits a change of control without the vote or consent of the unitholders.

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The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer the incentive distribution rights it owns to a third party at any time without the consent of our unitholders. If our general partner transfers the incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our business and increase quarterly distributions to unitholders over time as it would if it had retained ownership of the incentive distribution rights. For example, a transfer of the incentive distribution rights by our general partner could reduce the likelihood of SMP Holdings or Summit Investments selling or contributing additional midstream assets to us, as SMP Holdings and Summit Investments would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.
We may issue additional units without unitholder approval, which would dilute existing ownership interests.
Our partnership agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to the common units that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
our existing unitholders' proportionate ownership interest in us will decrease;
the amount of cash available for distribution on each unit may decrease;
because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
because the amount payable to holders of incentive distribution rights is based on a percentage of the total cash available for distribution, the distributions to holders of incentive distribution rights will increase even if the per-unit distribution on common units remains the same;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding unit may be diminished; and
the market price of the common units may decline.
SMP Holdings may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.
As of December 31, 2013, SMP Holdings held an aggregate of 14,691,397 common units and 24,409,850 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. In addition, we have agreed to provide SMP Holdings with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.
Our general partner has a limited call right that may require an investor to sell its units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of our outstanding common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, an investor may be required to sell its common units at an undesirable time or price and may not receive any return on its investment. An investor may also incur a tax liability upon a sale of its units. As of December 31, 2013, SMP Holdings owned 14,691,397 common units and 24,409,850 subordinated units. At the end of the subordination period, assuming no acquisitions, dispositions, retirement or additional issuance of common units (other than upon the conversion of the subordinated units), SMP Holdings will own 39,101,247 common units, or approximately 70.5% of our then-outstanding common units.
An investor's liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not

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been clearly established in some of the other states in which we do business. An investor could be liable for any and all of our obligations as if it was a general partner if a court or government agency were to determine that:
we were conducting business in a state but had not complied with that particular state's partnership statute; or
an investor's right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute control of our business.
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 Delaware Law, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.
If an investor is not an eligible holder, it may not receive distributions or allocations of income or loss on those common units and those common units will be subject to redemption.
We have adopted certain requirements regarding those investors who may own our common and subordinated units. Eligible holders are U.S. individuals or entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity's owners are U.S. individuals or entities subject to such taxation. If an investor is not an eligible holder, our general partner may elect not to make distributions or allocate income or loss on that investor's units, and it runs the risk of having its units redeemed by us at the lower of purchase price cost and the then-current market price. The redemption price may be paid in cash or by delivery of a promissory note, as determined by our general partner.
The New York Stock Exchange does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.
We have listed our common units on the New York Stock Exchange. Because we are a publicly traded partnership, the New York Stock Exchange does not require us to have, and we do not intend to have, a majority of independent directors on our general partner's board of directors or to establish a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the New York Stock Exchange's shareholder approval rules. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the New York Stock Exchange corporate governance requirements.

Tax Risks
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service (the "IRS") were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of

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our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, there would be material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.
Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.
Our unitholders' share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.
Because a unitholder will be treated as a partner to whom we will allocate taxable income that could be different in amount than the cash we distribute, a unitholder's allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if the unitholder receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take, and the IRS's positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. Any contest with the IRS, and the outcome of any IRS contest, may have an adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If a unitholder sells its common units, a gain or loss will be recognized for federal income tax purposes equal to the difference between the amount realized and the unitholder's tax basis in those common units. Because distributions in excess of a unitholder's allocable share of its net taxable income decrease its tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the common units the it sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than the its tax basis in those common units, even if the price it receives is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale of a unitholder's common units, whether or not representing gain, may be taxed as

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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 a unitholder sells its common units, it may incur a tax liability in excess of the amount of cash you 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. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and pay tax on their share of our taxable income. Tax-exempt entities and non-U.S. persons should consult a tax advisor before investing in our common units.
We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from our unitholders' sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders' tax returns.
We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We will prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations. Recently, however, the U.S. Treasury Department issued proposed regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose common units are loaned to a short seller to effect a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose common units are loaned to a short seller to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are advised to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.
We adopted certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general

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partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders' sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and would result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.
As a result of investing in our common units, our unitholders may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if the unitholders do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently conduct business in West Virginia, North Dakota, Texas and Colorado. Some of these states currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is the unitholder's responsibility to file all federal, state and local tax returns.

Item 1B. Unresolved Staff Comments.
Not applicable.

Item 2. Properties.
We currently have four natural gas gathering systems which provide our gathering, compression and dehydration services. They are (i) the Mountaineer Midstream system located in Doddridge and Harrison counties, West Virginia, (ii) the Bison Midstream system located in Mountrail and Burke counties, North Dakota, (iii) the DFW Midstream system located primarily in Tarrant County, Texas and (iv) the Grand River system located primarily in Garfield County, Colorado. For additional information on our gathering systems and their capacities, see Item 1. Business.
Our real property falls into two categories: (i) parcels that we own in fee and (ii) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our gathering systems and other major

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facilities are located are owned by us in fee title, and we believe that we have valid title to these lands. The remainder of the land on which our major facilities are located are held by us pursuant to long-term leases or easements between us and the underlying fee owner, or permits with governmental authorities. Our Predecessor leased or owned these lands without any material challenge known to us relating to the title to the land upon which our assets are located, and we believe that we have valid leasehold estates or fee ownership in such lands or valid permits with governmental authorities. We have no knowledge of any material 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 license. We believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses with the exception of certain ordinary course encumbrances and permits with governmental entities that have been applied for, but not yet issued.
In addition, we lease various office space under operating leases to support our operations. Our headquarters are located in Dallas, Texas, and we have additional regional corporate offices in Houston, Texas, Denver, Colorado and Atlanta, Georgia.

Item 3. Legal Proceedings.
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any significant legal or governmental proceedings.  In addition, we are not aware of any significant legal or governmental proceedings contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

Item 4. Mine Safety Disclosures.
Not applicable.


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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Our limited partner common units began trading on the New York Stock Exchange commencing with our initial public offering on September 28, 2012 at a price of $20.00 per common unit. Our ticker symbol is "SMLP." As of February 28, 2014, the market price for our common units was $40.58 per unit and there were approximately 3,800 common unitholders, including beneficial owners of common units held in street name. There is one record holder of our subordinated units. There is no established public trading market for our subordinated units.
The following table shows the high and low price per common unit, as reported by the New York Stock Exchange for the periods indicated.
 
Common unit price range
 
Cash distribution paid per common unit
 
High
 
Low
 
4th Quarter 2013
$38.20
 
$30.66
 
$0.46
3rd Quarter 2013
$35.40
 
$31.62
 
$0.44
2nd Quarter 2013
$35.40
 
$26.04
 
$0.42
1st Quarter 2013
$28.50
 
$18.67
 
$0.41
 
 
 
 
 
 
4th Quarter 2012
$21.50
 
$18.26
 
3rd Quarter 2012
$21.48
 
$20.57
 
There were no cash distributions paid during the third and fourth quarters of 2012. On January 23, 2014, the board of directors of our general partner declared a distribution of $0.48 per unit for the quarterly period ended December 31, 2013. The distribution, which totaled approximately $26.4 million , was paid on February 14, 2014 to unitholders of record at the close of business on February 7, 2014.
Our Cash Distribution Policy and Restrictions on Distributions
General
Our Cash Distribution Policy. Our partnership agreement requires us to distribute all of our available cash quarterly. Our policy is to distribute to our unitholders an amount of cash each quarter that is equal to or greater than the minimum quarterly distribution stated in our partnership agreement. Generally, our available cash is our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case were we subject to federal income tax. For additional information, see Note 6 to the audited consolidated financial statements.
Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy. There is no guarantee that our unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or any other distribution except to the extent we have available cash as defined in our partnership agreement. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including the following:
Our cash distribution policy is subject to restrictions on distributions under our amended and restated revolving credit facility. Our amended and restated revolving credit facility contains financial tests and covenants that we must satisfy. Should we be unable to satisfy these restrictions, we may be prohibited from making cash distributions notwithstanding our stated cash distribution policy.
Our general partner has the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment or increase of those cash reserves could result in a reduction in cash distributions to you from the levels we currently anticipate pursuant to our stated distribution policy. Any determination to establish cash reserves made by our general partner in good faith will be binding on our unitholders.

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Although our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to distribute all of our available cash, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders other than in certain limited circumstances where no unitholder approval is required. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by Summit Investments) after the subordination period has ended. As of February 28, 2014, SMP Holdings owned our general partner as well as 14,691,397 common units and all of our 24,409,850 subordinated units.
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, taking into consideration the terms of our partnership agreement.
Under Delaware law, 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 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 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 and to the extent our cash available for distribution materially declines, we may elect to reduce our quarterly distribution rate to service or repay our debt or fund expansion capital expenditures.
Our Minimum Quarterly Distribution
The board of directors of our general partner has established a minimum quarterly distribution of $0.40 per unit per quarter, or $1.60 per unit per year, to be paid no later than 45 days after the end of each fiscal quarter. This equates to an aggregate cash distribution (including distribution equivalent rights) of approximately $21.9 million per quarter, or approximately $87.8 million per year, based on all of the units outstanding as of February 28, 2014 (including awards of phantom units and restricted units under the 2012 Long Term Incentive Plan, or "LTIP").
Our general partner is entitled to 2.0% of all distributions that we make prior to our liquidation. In the future, our general partner's initial 2.0% interest in these distributions may be reduced if we issue additional units and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest.
The following table sets forth the number of common and subordinated units outstanding as of February 28, 2014 and the number of unit equivalents represented by the 2.0% general partner interest and the aggregate distribution amounts payable on such units during the year at our minimum quarterly distribution rate of $0.40 per unit per quarter, or $1.60 per unit on an annualized basis.
 
Minimum Quarterly Distribution
 
Number of units
 
Per quarter
 
Annualized
 
(Dollars in thousands)
Publicly held common units
14,388,469

 
$
5,755

 
$
23,022

Common units held by SMP Holdings
14,691,397

 
5,877

 
23,506

Subordinated units held by SMP Holdings
24,409,850

 
9,764

 
39,056

LTIP participant phantom units and restricted units (1)
283,682

 
113

 
454

2.0% general partner interest
1,091,453

 
437

 
1,746

Total
54,864,851

 
$
21,946

 
$
87,784

__________
(1) Represents distribution equivalent rights on awards of phantom units and restricted units not yet vested.
The subordination period generally will end if we have earned and paid at least $1.60 on each outstanding common unit and subordinated unit and the corresponding distribution on our general partner's 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2015. The subordination period will automatically terminate and all of the subordinated units will convert into an equal number of common

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units if we have earned and paid at least $2.40 (150.0% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and the corresponding distribution on our general partner's 2.0% interest and the related distribution on the incentive distribution rights for any four consecutive quarter period ending on or after December 31, 2013.
If we do not pay the minimum quarterly distribution on our common units, our common unitholders will not be entitled to receive such payments in the future except during the subordination period. To the extent we have available cash in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common units, we will use this excess available cash to pay any distribution arrearages related to prior quarters before any cash distribution is made to holders of subordinated units. Our subordinated units will not accrue arrearages for unpaid quarterly distributions or quarterly distributions less than the minimum quarterly distribution.
Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. The actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. We will pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about seven days prior to such distribution date. We will make the distribution on the business day immediately preceding the indicated distribution date if the distribution date falls on a holiday or non-business day.
Stock Performance Table
The following graph compares the cumulative total unitholder return on our common units since the IPO to the cumulative total return of the S&P 500 Stock Index and the Alerian MLP Index ("AMZX") by assuming $100 was invested in each investment option as of September 28, 2012, the date of the IPO. The Alerian MLP Index is a composite of the 50 most prominent energy Master Limited Partnerships, or MLPs, and is calculated using a float-adjusted, capitalization-weighted methodology.
Issuer Purchases of Equity Securities
We made no repurchases of our common units during the quarter ended December 31, 2013.
Equity Compensation Plans
The information relating to SMLP’s equity compensation plans required by Item 5 is included in Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

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Item 6. Selected Financial Data.
The selected consolidated financial data presented as of December 31, 2013, 2012, 2011, 2010 and 2009 and for the years ended December 31, 2013, 2012, 2011, 2010 and for the period from September 3, 2009 to December 31, 2009 have been derived from the audited consolidated financial statements of SMLP and its Predecessor.
The selected consolidated financial data for the period from January 1, 2009 to September 3, 2009 have been derived from the audited financial statements of our Initial Predecessor. The historical consolidated financial statements and related notes of our Initial Predecessor:
(i)
have been carved out of the accounting records maintained by Energy Future Holdings Corp. and its subsidiaries. Certain accounts such as trade accounts receivables, accounts payable, prepaid expenses and certain accrued liabilities relating to the activities of our Initial Predecessor were recorded on the books of other Energy Future Holdings Corp. entities and estimates of those accounts have been included in the consolidated financial statements;
(ii)
include an estimate for general and administrative expenses, as Energy Future Holdings Corp. did not allocate any of the central finance and administrative costs to this operating entity;
(iii)
reflect the operation of the DFW Midstream system with different business strategies and as part of a larger business rather than the stand-alone fashion in which we operate it; and
(iv)
do not include any results from certain natural gas gathering assets that we acquired from Chesapeake on September 3, 2009 that are included in the DFW Midstream system.
For the purposes of these financial statements, SMLP's results of operations reflect the results of operations of (i) Bison Midstream since February 16, 2013 and (ii) Mountaineer Midstream since June 22, 2013. Because the drop down of the Bison Midstream system (the "Bison Drop Down") on June 5, 2013 was executed between entities under common control, SMLP recognized the acquisition of Bison Midstream at SMP Holdings' historical cost which reflected its fair value accounting for the acquisition of Bear Tracker Energy, LLC. The excess of SMP Holdings' net investment in Bison Midstream over the purchase price paid by SMLP was recognized as an addition to partners' capital. Due to the common control aspect, the Bison Drop Down was accounted for by the Partnership on an “as if pooled” basis for all periods in which common control existed.
SMLP completed its IPO on October 3, 2012. For the year ended December 31, 2012, these financial statements include the Predecessor's results of operations through the date of SMLP's IPO. The Grand River system was acquired on October 27, 2011. We have included its financial results in the financial statements of SMLP and the Predecessor since the date of acquisition . On September 3, 2009, Summit Investments acquired a controlling interest in DFW Midstream. We refer to DFW Midstream as our Initial Predecessor for the period prior to such date.
Due to the various asset acquisitions and the associated shift in business strategies relative to those of the Predecessor and Initial Predecessor, SMLP's financial position and results of operations may not be comparable to the historical financial position and results of operations of the Predecessor and the Initial Predecessor.

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The following table presents selected balance sheet and other data as of the date indicated.
 
December 31,
 
2013
 
2012
 
2011
 
2010
 
2009
 
(In thousands, except per-unit amounts)
Balance sheet data:
 
 
 
 
 
 
 
 
 
Total assets
$
1,639,915

 
$
1,063,511

 
$
1,030,264

 
$
340,095

 
$
215,982

Total long-term debt
586,000

 
199,230

 
349,893

 

 

Partners' capital
969,143

 
819,247

 
n/a

 
n/a

 
n/a

Membership interests
n/a

 
n/a

 
640,818

 
307,370

 
185,066

 
 
 
 
 
 
 
 
 
 
Other data:
 
 
 
 
 
 
 
 
 
Market price per common unit
$
36.65

 
$
19.83

 
n/a

 
n/a

 
n/a

__________
n/a - Not applicable
The following table presents selected statement of operations data by entity for the periods indicated.
 
SMLP
 
Initial Predecessor
 
Year ended December 31,
 
Period from September 3, 2009 to December 31, 2009
 
Period from January 1, 2009 to September 3, 2009
 
2013
 
2012
 
2011
 
2010
 
 
 
(In thousands, except per-unit amounts)
Statement of operations data:
 
 
 
 
 
 
 
 
 
 
 
Total revenues
$
242,806

 
$
165,499

 
$
103,552

 
$
31,676

 
$
1,733

 
$
1,910

Total costs and expenses
179,160

 
110,334

 
61,864

 
23,412

 
8,350

 
2,492

Interest expense
19,173

 
7,340

 
1,029

 

 

 
247

Affiliated interest expense

 
5,426

 
2,025

 

 

 

Net income (loss)
43,636

 
41,726

 
37,951

 
8,172

 
(6,606
)
 
(837
)
 
 
 
 
 
 
 
 
 
 
 
 
Earnings per limited partner unit:
 
 
 
 
 
 
 
 
 
 
 
Common unit – basic
$
0.86

 
$
0.35

 
n/a

 
n/a

 
n/a

 
n/a

Common unit – diluted
$
0.86

 
$
0.35

 
n/a

 
n/a

 
n/a

 
n/a

Subordinated unit – basic and diluted
$
0.79

 
$
0.35

 
n/a

 
n/a

 
n/a

 
n/a

 
 
 
 
 
 
 
 
 
 
 
 
Other financial data:
 
 
 
 
 
 
 
 
 
 
 
EBITDA
$
125,389

 
$
90,656

 
$
53,363

 
$
12,353

 
$
(6,293
)
 
$
300

Adjusted EBITDA
145,543

 
103,300

 
56,803

 
12,353

 
(6,293
)
 
300

Capital expenditures
81,911

 
76,698

 
78,248

 
153,719

 
19,519

 
40,777

Acquisition capital expenditures (1)
458,914

 

 
589,462

 

 
44,896

 

Distributable cash flow
111,683

 
88,492

 
50,980

 
11,726

 
(6,275
)
 
300

Distributions declared per unit (2)
1.795

 
0.410

 
n/a

 
n/a

 
n/a

 
n/a

__________
n/a - Not applicable
(1) Reflects cash paid and value of units issued, if any, to fund the acquisitions of the Bison Midstream and Mountaineer Midstream systems in 2013, Red Rock Gathering, LLC ("Red Rock") in 2012, the Grand River system in 2011 and the DFW Midstream system in 2009.

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(2) For 2013, represents the distributions declared in April 2013 for the first quarter of 2013, July 2013 for the second quarter of 2013, October 2013 for the third quarter of 2013 and January 2014 for the fourth quarter of 2013. For 2012, represents the distribution declared in January 2013 for the fourth quarter of 2012.
For a detailed discussion of the data presented above, including information regarding our use of EBITDA, adjusted EBITDA and distributable cash flow as well as their reconciliations to net income and net cash flows provided by operating activities, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. The preceding tables should also be read in conjunction with the audited consolidated financial statements and related notes.
UNAUDITED QUARTERLY FINANCIAL DATA
Summarized information on the consolidated results of operations for each of the quarters during the two-year period ended December 31, 2013, follows.
 
Quarter ended
December 31, 2013
 
Quarter ended
September 30, 2013
 
Quarter ended
June 30,
2013
 
Quarter ended
March 31,
2013
 
(In thousands, except per-unit amounts)
Total revenues
$
69,298

 
$
63,096

 
$
59,285

 
$
51,126

 
 
 
 
 
 
 
 
Net income attributable to partners
$
16,345

 
$
6,691

 
$
8,068

 
$
12,480

Less: net income attributable to general partner, including IDRs
490

 
134

 
161

 
250

Net income attributable to limited partners
$
15,855

 
$
6,557

 
$
7,907

 
$
12,230

 
 
 
 
 
 
 
 
Earnings per limited partner unit:
 
 
 
 
 
 
 
Common unit – basic
$
0.30

 
$
0.12

 
$
0.16

 
$
0.25

Common unit – diluted
$
0.29

 
$
0.12

 
$
0.16

 
$
0.25

Subordinated unit – basic and diluted
$
0.30

 
$
0.12

 
$
0.16

 
$
0.25

 
Quarter ended
December 31, 2012
 
Quarter ended
September 30, 2012
 
Quarter ended
June 30,
2012
 
Quarter ended
March 31,
2012
 
(In thousands, except per-unit amounts)
Total revenues
$
48,634

 
$
40,975

 
$
40,107

 
$
35,783

 
 
 
 
 
 
 
 
Net income attributable to partners and net income
$
17,614

 
$
7,396

 
$
9,129

 
$
7,587

Less: net income attributable to general partner
352

 
 
 
 
 
 
Net income attributable to limited partners
$
17,262

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Earnings per limited partner unit:
 
 
 
 
 
 
 
Common unit – basic
$
0.35

 
 
 
 
 
 
Common unit – diluted
$
0.35

 
 
 
 
 
 
Subordinated unit – basic and diluted
$
0.35

 
 
 
 
 
 

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
This MD&A is intended to inform the reader about matters affecting the financial condition and results of operations of SMLP and its subsidiaries. As a result, the following discussion should be read in conjunction with the audited consolidated financial statements and notes thereto included in this report. Among other things, those financial statements and the related notes include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that constitute our plans, estimates and beliefs. These forward-looking statements involve numerous risks and uncertainties, including, but not limited to,

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those discussed in Forward-Looking Statements on page ii of this Annual Report on Form 10-K. Actual results may differ materially from those contained in any forward-looking statements.

Overview
We are a growth-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in North America. We gather natural gas from both dry gas and liquids-rich regions. Dry gas regions contain natural gas reserves that are primarily composed of methane. Liquids-rich regions include natural gas reserves that contain natural gas liquids, or NGLs, in addition to methane. We currently operate natural gas gathering systems in four unconventional resource basins: (i) the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia; (ii) the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; (iii) the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and (iv) the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado. We believe that our gathering systems are well positioned to capture additional volumes from increased producer activity in these regions in the future.
Our results are driven primarily by the volumes of natural gas that we gather across our systems. We contract with producers to gather natural gas from pad sites and central receipt points connected to our systems, which we then compress and dehydrate for delivery to downstream pipelines for ultimate delivery to third-party processing plants and/or end users.
We generate the majority of our revenue from the natural gas gathering services that we provide to our natural gas producer customers under long-term, primarily fee-based natural gas gathering agreements. Under these agreements, we are paid a fixed fee based on the volume and thermal content of the natural gas we gather. These agreements enhance the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk, with the exception of the natural gas that we retain in-kind to offset the power costs we incur to operate our electric-drive compression assets on the DFW Midstream system. We also earn revenue from our marketing of natural gas and natural gas liquids and from the sale of physical natural gas purchased from our customers under percentage-of-proceeds arrangements, which can expose us to commodity price risk. We sell condensate retained from our gathering services at Grand River Gathering.
We also have indirect exposure to changes in commodity prices in that persistent low commodity prices may cause our customers to delay drilling or temporarily shut in production, which would reduce the volumes of natural gas that we gather. If our customers delay drilling or temporarily shut-in production, our minimum volume commitments assure us that we will receive a certain amount of revenue from our customers.
Most of our gas gathering agreements are underpinned by areas of mutual interest and MVCs. Our areas of mutual interest cover over 1.0 million acres in the aggregate, have original terms that range from five years to 25 years, and provide that any natural gas producing wells drilled by our customers within the areas of mutual interest will be shipped on our gathering systems. The MVCs, which totaled 3.6 Tcf at December 31, 2013 and average approximately 1,034 MMcf/d through 2018, are designed to ensure that we will generate a certain amount of revenue from each customer over the life of the respective gas gathering agreement, whether by collecting gathering fees on actual throughput or from cash payments to cover any minimum volume commitment shortfall. Our minimum volume commitments have remaining terms that range from three to 13 years and, as of December 31, 2013 , had a weighted-average remaining life of 10.2 years, assuming minimum throughput volumes for the remainder of the term.
For additional information on our gathering systems, see the "Business" section included in this Annual Report and "Results of Operations—Combined Overview" below.

Trends and Outlook
Our business has been, and we expect our future business to continue to be, affected by the following key trends:
Natural gas supply and demand dynamics;
Growth in production from U.S. shale plays;
Interest rate environment; and
Rising operating costs and inflation.

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Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.
Natural gas and crude oil supply and demand dynamics. Natural gas continues to be a critical component of energy supply and demand in the United States. Recently, the price of natural gas has seen an increase with NYMEX natural gas futures price at $4.23 per MMBtu as of December 31, 2013 compared with $3.35 per MMBtu as of December 31, 2012. These marks compare with a high of $13.58 per MMBtu in July 2008. The increase in natural gas prices from 2012 to 2013 was primarily attributable to an unseasonably cold winter in 2013, which resulted in higher than normal residential consumption of natural gas. As a result, the amount of natural gas in storage in the continental United States decreased to approximately 3.0 Tcf as of December 27, 2013 from approximately 3.5 Tcf as of December 28, 2012, compared with a ten-year historical December average of 3.3 Tcf.
Current natural gas prices continue to be lower than historical prices due in part to increased production, especially from unconventional sources, such as natural gas shale plays and the effects of the economic downturn starting in 2008. According to the U.S. Energy Information Administration (the "EIA"), average annual natural gas production in the United States increased 19.2% to 65.7 Bcf/d in 2012 from from 55.1 Bcf/d in 2008. Over the same time period, natural gas consumption increased only 9.7% to 69.8 Bcf/d. In response to lower natural gas prices, the number of natural gas drilling rigs has declined from approximately 1,347 as of December 26, 2008 to approximately 374 as of December 27, 2013, according to Baker Hughes, as a number of producers have reallocated capital from natural gas exploration and production activities to higher yielding crude oil exploration and production activities. We believe that over the short term, until the supply overhang has been reduced and the economy sees more robust growth, natural gas prices are likely to be constrained.
Over the long term, we believe that the prospects for continued natural gas demand are favorable and will be driven by population and economic growth, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation due to the low prices of natural gas and stricter government environmental regulations on the mining and burning of coal. For example, according to the EIA, coal-fired power plants generated 37% of the electricity in the United States in 2012, compared with 48% in 2008. In January 2013, the EIA projected total annual domestic consumption of natural gas to increase from approximately 62.7 Bcf/d in 2009 to approximately 80.7 Bcf/d in 2040. Consistent with the rise in consumption, the EIA projects that total domestic natural gas production will continue to grow through 2040 to 90.7 Bcf/d. The EIA also projects the United States to be a net exporter of liquefied natural gas, or LNG, by 2016, with U.S. exports of LNG projected to rise to 4.4 Bcf/d in 2027. We believe that increasing consumption of natural gas will continue to drive natural gas drilling and production over the long term throughout the United States.
In addition, in connection with the Bison Drop Down, we are now affected by crude oil supply and demand dynamics. Crude oil has been the focus of recent upstream activity in the United States and continues to play a significant role in the energy market. United States domestic crude oil production has increased by 49% from 5.0 MMBbl/d in 2008 to 7.5 MMBbl/d in 2013 according to the EIA. Over the long term, the domestic production of crude oil will continue to increase according to the EIA. The growth will continue to come from increases in shale and tight crude oil production, which will be spurred by additional technological advances and elevated oil prices. According to the EIA, about 25.3 billion barrels of tight oil will be produced in the U.S. cumulatively from 2012 through 2040 and the Bakken Shale is expected to contribute 32% of this production.
Growth in production from U.S. shale plays. Over the past several years, a fundamental shift in production has emerged with the growth of natural gas production from unconventional resources (defined by the EIA as natural gas produced from shale formations and coalbeds). While the EIA expects total domestic natural gas production to grow from 20.7 Tcf in 2009 to 33.2 Tcf in 2040, it expects shale gas production to grow to 16.7 Tcf in 2040, representing 50% of total U.S. dry gas production. Most of this increase is due to the emergence of unconventional natural gas plays and advances in technology that have allowed producers to extract significant volumes of natural gas from these plays at cost-advantaged per-unit economics when compared to most conventional plays.
In recent years, well-capitalized producers have leased large acreage positions in the Piceance Basin and the Barnett, Bakken and Marcellus shale plays and other unconventional resource plays. To help fund their drilling program in many of these areas, a number of producers have also entered into joint venture arrangements with large international operators, industrial manufacturers and private equity sponsors. These producers and their joint venture partners have committed significant capital to the development of the Piceance Basin and the Barnett, Bakken and Marcellus shale plays and other unconventional resource plays, which we believe will result in sustained drilling activity.

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As a result of the current low natural gas price environment, some natural gas producers have cut back or suspended their drilling operations in certain dry gas regions where the economics of natural gas production are less favorable. Drilling and production activities focused in liquids-rich regions have continued and, in some cases, have increased, as the high Btu content associated with liquids-rich production enhances overall drilling economics, even in a low natural gas price environment.
Interest rate environment. The credit markets have continued to experience near-record lows in interest rates. As the overall economy strengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. This could affect our ability to access the debt capital markets to the extent we may need to in the future to fund our growth. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Although this could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.
Rising operating costs and inflation. The current high level of crude oil and natural gas exploration, development and production activities across the United States has resulted in increased competition for personnel and equipment. This is causing increases in the prices we pay for labor, supplies and property, plant and equipment. An increase in the general level of prices in the economy could have a similar effect. We attempt to recover increased costs from our customers, but there may be a delay in doing so or we may be unable to recover all of these costs. To the extent we are unable to procure necessary supplies or recover higher costs, our operating results will be negatively impacted.

How We Evaluate Our Operations
We conduct our operations in the midstream sector with four operating segments. However, due to their similar characteristics and how we manage our business, we have aggregated these segments into a single reporting segment for disclosure purposes. Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on a regular basis for consistency and trend analysis. These metrics include:
throughput volume;
operation and maintenance expenses;
EBITDA and adjusted EBITDA; and
distributable cash flow.
Throughput Volume
The volume of natural gas that we gather depends on the level of production from natural gas or crude oil wells connected to our gathering systems. Aggregate production volumes are impacted by the overall amount of drilling and completion activity, as production must be maintained or increased by new drilling or other activity, because the production rate of crude oil and natural gas wells decline over time.
As a result, we must continually obtain new supplies of natural gas to maintain or increase the throughput volume on our systems. Our ability to maintain or increase throughput volumes from existing customers and obtain new supplies of natural gas is impacted by:
successful drilling activity within our areas of mutual interest;
the level of work-overs and recompletions of wells on existing pad sites to which our gathering systems are connected;
the number of new pad sites in our areas of mutual interest awaiting connections;
our ability to compete for volumes from successful new wells in the areas in which we operate outside of our existing areas of mutual interest; and
our ability to gather natural gas that has been released from commitments with our competitors.
Operation and Maintenance Expenses
We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating our assets. Direct labor costs, compression costs, insurance costs, ad valorem and

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property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operation and maintenance expense. Other than utilities expense, these expenses are relatively stable and largely independent of volumes delivered through our gathering systems but may fluctuate depending on the activities performed during a specific period.
The majority of the compressors on our DFW Midstream system are electric driven and power costs are directly correlated to the run-time of these compressors, which depends directly on the volume of natural gas gathered. As part of our contracts with our DFW Midstream system customers, we physically retain a percentage of throughput volumes that we subsequently sell to offset the power costs we incur. In addition, we pass along the fees associated with costs we incur on behalf of certain DFW Midstream system customers to deliver pipeline quality natural gas to third-party pipelines. With respect to the Mountaineer Midstream, Bison Midstream and Grand River systems, we either (i) consume physical gas on the system to operate our gas-fired compressors or (ii) charge our customers for the power costs we incur to operate our electric-drive compressors.
EBITDA, Adjusted EBITDA and Distributable Cash Flow
We define EBITDA as net income, plus interest expense, income tax expense, and depreciation and amortization expense, less interest income and income tax benefit. We define adjusted EBITDA as EBITDA plus unit-based compensation, adjustments related to MVC shortfall payments and loss on asset sales, less gain on asset sales. We define distributable cash flow as adjusted EBITDA plus cash interest income, less cash paid for interest expense and income taxes, senior notes interest expense and maintenance capital expenditures.
EBITDA, adjusted EBITDA and distributable cash flow are used as supplemental financial measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others.
EBITDA and adjusted EBITDA are used to assess:
the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unitholders and general partner;
our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and
the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.
In addition, adjusted EBITDA is used to assess:
the financial performance of our assets without regard to the impact of the timing of minimum volume commitments shortfall payments under our gas gathering agreements, the impact of unit-based compensation or the timing of gain or loss on asset sales.
Distributable cash flow is used to assess:
the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders; and
the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

Results of Operations
Items Affecting the Comparability of Our Financial Results
SMLP's historical results of operations may not be comparable to its future results of operations for the reasons described below:
Based on the terms of our partnership agreement, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations, borrowings under our revolving credit facility and future issuances of equity and debt securities. Prior to the IPO, we largely relied

57


on internally generated cash flows and capital contributions from the Sponsors to satisfy our capital expenditure requirements;
Our historical results of operations may not be comparable to our future results of operations due in part to:
(i)
Our June 2013 acquisitions. The audited consolidated financial statements reflect the results of operations of: (i) Bison Midstream since February 16, 2013 and (ii) Mountaineer Midstream since June 22, 2013. For additional information, see Notes 1, 5, 6 and 13 to the audited consolidated financial statements;
(ii)
Our October 2011 acquisition of Grand River Gathering. The audited consolidated financial statements reflect the results of operations of Grand River Gathering since November 1, 2011. For additional information, see Notes 1 and 13 to the audited consolidated financial statements;
(iii)
Our IPO, which was completed on October 3, 2012. Incremental public entity costs include:
expenses associated with annual and quarterly reporting;
tax return and Schedule K-1 preparation and distribution expenses;
Sarbanes-Oxley compliance expenses;
expenses associated with listing on the NYSE;
independent auditor fees;
legal fees;
investor relations expenses;
registrar and transfer agent fees;
director and officer liability insurance costs; and
director compensation.
These incremental general and administrative expenses are not reflected in the historical consolidated financial statements prior to the IPO.
Overview of the Years Ended December 31, 2013, 2012 and 2011
Revenues. For the year ended December 31, 2013, total revenues increased $77.3 million to $242.8 million from $165.5 million largely as a result of Bison Midstream's contribution to natural gas, NGLs and condensate sales and other, Mountaineer Midstream's contribution to gathering services and other fees and an increase in revenues for the DFW Midstream system. Total revenues for the year ended December 31, 2013 included a $50.7 million contribution from Bison Midstream and a $9.6 million contribution from Mountaineer Midstream.
For the year ended December 31, 2012, total revenues increased primarily as a result of the October 2011 acquisition of the Grand River system and increased throughput volumes on the DFW Midstream system due to its continued build out. Total revenues for the year ended December 31, 2012 included a $72.0 million contribution from Grand River Gathering, compared with a $12.8 million contribution in 2011.
Costs and Expenses. For the year ended December 31, 2013, total costs and expenses increased $68.8 million , or 62% , primarily as a result of the acquisitions of Bison Midstream and Mountaineer Midstream and an increase in expenses at DFW Midstream. Total costs and expenses for the year ended December 31, 2013 included a $53.5 million contribution from Bison Midstream and a $7.3 million contribution from Mountaineer Midstream.
During the year ended December 31, 2012, total costs and expenses increased $48.5 million , or 78% , largely driven by Grand River Gathering's contribution to operation and maintenance expense and depreciation and amortization expense. Total costs and expenses for the year ended December 31, 2012 included a $54.6 million contribution from Grand River, compared with a $8.7 million contribution in 2011.
Volumes. Our revenues are primarily attributable to the volume of natural gas that we gather and compress and the rates we charge for those services. For the year ended December 31, 2013, our aggregate throughput volumes increased to an average of 990 MMcf/d compared with an average of 929 MMcf/d for the year ended December 31, 2012. The 2013 increase in volume throughput largely reflects the combined effect of contributions from Bison Midstream and Mountaineer Midstream and a temporary production curtailment by one of our largest producer customers on the DFW Midstream system during the first and second quarters of 2012, partially offset by the volume throughput declines on the Grand River system.

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For the year ended December 31, 2012, our combined throughput volumes increased to an average of 929 MMcf/d compared with an average of 431 MMcf/d for the year ended December 31, 2011. The 2012 increase in volume throughput largely reflects the contribution from the Grand River system and the continued development of the DFW Midstream system as well as the 2012 impact of the temporary production curtailment noted above.
The following table presents certain consolidated and other financial and operating data for the periods indicated.
 
Year ended December 31,
 
Percentage Change
 
2013
 
2012
 
2011
 
2013 v. 2012
 
2012 v. 2011
 
(Dollars in thousands)
Revenues:
 
 
 
 
 
 
 
 
 
Gathering services and other fees
$
174,506

 
$
149,371

 
$
91,421

 
17
 %
 
63
 %
Natural gas, NGLs and condensate sales and other
69,332

 
16,320

 
12,439

 
*

 
31
 %
Amortization of favorable and unfavorable contracts (1)
(1,032
)
 
(192
)
 
(308
)
 
*

 
*

Total revenues
242,806

 
165,499

 
103,552

 
47
 %
 
60
 %
Costs and expenses:
 
 
 
 
 
 
 
 
 
Operation and maintenance
59,972

 
51,658

 
29,855

 
16
 %
 
73
 %
Cost of natural gas and NGLs
31,036

 

 

 
*

 
*

General and administrative
24,558

 
21,357

 
17,476

 
15
 %
 
22
 %
Transaction costs
2,770

 
2,020

 
3,166

 
37
 %
 
(36
)%
Depreciation and amortization
60,824

 
35,299

 
11,367

 
72
 %
 
*

Total costs and expenses
179,160

 
110,334

 
61,864

 
62
 %
 
78
 %
Other (expense) income
(108
)
 
9

 
12

 
*

 
(25
)%
Interest expense
(19,173
)
 
(7,340
)
 
(1,029
)
 
*

 
*

Affiliated interest expense

 
(5,426
)
 
(2,025
)
 
(100
)%
 
*

Income before income taxes
44,365

 
42,408

 
38,646

 
5
 %
 
10
 %
Income tax expense
(729
)
 
(682
)
 
(695
)
 
7
 %
 
(2
)%
Net income
$
43,636

 
$
41,726

 
$
37,951

 
5
 %
 
10
 %
 
 
 
 
 
 
 
 
 
 
Other Financial Data:
 
 
 
 
 
 
 
 
 
EBITDA (2)
$
125,389

 
$
90,656

 
$
53,363

 
38
 %
 
70
 %
Adjusted EBITDA (2)
145,543

 
103,300

 
56,803

 
41
 %
 
82
 %
Capital expenditures   (3)
81,911

 
76,698

 
78,248

 
7
 %
 
(2
)%
Acquisition capital expenditures (4)
458,914

 

 
589,462

 
*

 
*

Distributable cash flow (2)(3)
111,683

 
88,492

 
50,980

 
26
 %
 
74
 %
 
 
 
 
 
 
 
 
 
 
Operating Data:
 
 
 
 
 
 
 
 
 
Miles of pipeline (end of period)
804

 
399

 
372

 
102
 %
 
7
 %
Aggregate average throughput (MMcf/d)
990

 
929

 
431

 
7
 %
 
116
 %
__________
* Not considered meaningful
(1) The amortization of favorable and unfavorable contracts relates to gas gathering agreements that were deemed to be above or below market at the acquisition of the DFW Midstream system. We amortize these contracts on a units-of-production basis over the life of the applicable contract. The life of the contract is the period over which the contract is expected to contribute directly or indirectly to our future cash flows.
(2) Includes transaction costs. These unusual and non-recurring expenses are settled in cash. See "Non-GAAP Financial Measures" below for additional information on EBITDA, adjusted EBITDA and distributable cash flow as well as their reconciliations to the most directly comparable GAAP financial measure.
(3) In the fourth quarter of 2012, we began tracking maintenance capital expenditures for the purposes of calculating distributable cash flow. Prior to the fourth quarter of 2012, we did not distinguish between maintenance and expansion capital expenditures. For the year ended December 31, 2012, distributable cash flow includes an estimate for the portion of total capital expenditures that were maintenance capital expenditures for nine months ended September 30, 2012. For the year ended

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December 31, 2011, distributable cash flow includes an estimate for the portion of total capital expenditures that were maintenance capital expenditures.
(4) Reflects cash paid and value of units issued, if any, to fund the acquisitions of the Bison Midstream and Mountaineer Midstream systems in 2013 and the Grand River system in 2011.
System Overview. Operating data by system as of or for the year ended December 31 follows.
 
Mountaineer
Midstream (1)
 
Bison
Midstream (1)
 
DFW
Midstream
 
Grand
River
 
2013
 
2013
 
2013
 
2012
 
2011
 
2013
 
2012
 
2011
Miles of pipeline (end of year)
41

 
343

 
119

 
110

 
104

 
301

 
289

 
268

Aggregate average annual throughput (MMcf/d)
87 (2)

 
14 (3)

 
391

 
354

 
333

 
498

 
575

 
98 (4)

Average fee per Mcf
n/a

 
$
3.86

 
$
0.59

 
$
0.58

 
$
0.59

 
$
0.36

 
$
0.30

 
$
0.31

Total Remaining MVC Commitment (Bcf)
n/a

 
29

 
263

 
372

 
488

 
1,803

 
1,980

 
2,144

Average daily MVCs through 2018 (MMcf/d)(end of year)
n/a

 
14
 
141
 
163

 
175

 
517
 
511

 
502

Weighted- average remaining contract life (end of year) (5)
n/a

 
6.5

 
6.2

 
7.2

 
8.2

 
11.6

 
12.6

 
13.6

__________
(1) Gathering system was not an asset of SMLP during 2012 and 2011.
(2) For the year ended December 31, 2013. For the period of SMLP's ownership in 2013, average throughput was 164 MMcf/d.
(3) For the year ended December 31, 2013. For the period of SMLP's ownership in 2013, average throughput was 16 MMcf/d.
(4) For the year ended December 31, 2011. For the period of SMLP's ownership in 2011, average throughput was 586 MMcf/d.
n/a - Contract terms excluded for confidentiality purposes.
(5) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate).
Mountaineer Midstream. For the year ended December 31, 2013, volume throughput for the Mountaineer Midstream system, which was acquired in late June 2013, was impacted by temporary processing capacity curtailments resulting from a line break on one of MarkWest’s NGL pipelines which forced the Mountaineer Midstream system to curtail its natural gas deliveries to MarkWest's Sherwood Processing Complex beginning in August 2013. The affected NGL pipeline was returned to service mid-October 2013 and returned to pre-curtailment levels by November 2013. Despite the curtailment, Mountaineer Midstream experienced sequential quarterly volume throughput increases from Antero, its sole customer, consistent with Antero’s development activities upstream of Mountaineer Midstream’s gathering infrastructure and in line with MarkWest’s processing capacity expansions at its Sherwood Processing Complex.
Bison Midstream. Bison Midstream system volume throughput during the year ended December 31, 2013, was impacted by temporary operational interruptions across the system due to water hydrate issues during the third and fourth quarters of 2013. These operational issues were resolved during the first quarter of 2014. Volume throughput in 2013 was also impacted by temporary interruptions, which occurred throughout the second, third and fourth quarters of 2013 as we continued to install new compression assets designed to increase the system's throughput capacity. Lower volume throughput at Bison Midstream was partially offset by a new natural gas purchase agreement with Aux Sable Midstream, LLC which became effective in August 2013 and provides for long-term access to natural gas processing capacity and improved processing economics for Bison Midstream and its customers.
DFW Midstream. The increase in DFW Midstream system volume throughput during the year ended December 31, 2013 was primarily due to the prior-year impact of a temporary production curtailment by one of our largest producer customers in the first and second quarters of 2012. Volume throughput for the DFW Midstream system in

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2013 was also impacted by multiple customers temporarily shutting-in several large pad sites during the third and fourth quarters to drill and/or complete new wells. While this activity is beneficial over the long term, it can create volume and cash flow volatility. Volume throughput in 2013 also reflects higher volumes in the first quarter of 2013, which benefited from the January 2013 commissioning of a compressor which increased system throughput capacity from 410 MMcf/d to 450 MMcf/d.
During the year ended December 31, 2012, volume throughput on the DFW Midstream system increased largely as a result of the system's continued build-out and an increase in well connections, partially offset by the impact of the production curtailment noted above.
Grand River. Grand River system volume throughput declined during the years ended December 31, 2013 and 2012 primarily due to lower drilling activity and the natural decline of previously drilled Mancos/Niobrara wells in the Orchard Field. Our gas gathering agreements for the Grand River system include MVCs that, in the aggregate, increase over the next several years. The majority of the volume declines came from producers that are subject to MVCs. As a result, the lower volume throughput for the Grand River system during 2013 primarily translated into larger MVC shortfall payments.
Gathering services and other fees. Gathering services and other fees increased during the year ended December 31, 2013, largely as a result of our acquisitions of the Bison Midstream and Mountaineer Midstream systems and throughput volumes on the DFW Midstream system. Gathering services and other fees in 2013 included a $12.6 million contribution from the Bison Midstream system and a $9.6 million contribution from the Mountaineer Midstream system. The aggregate average throughput rate for the year ended December 31, 2013 was approximately $0.50 per Mcf, compared with approximately $0.41 per Mcf for the year ended December 31, 2012. The year-over-year increase was largely driven by the proportionate contribution of throughput volumes from our DFW Midstream and Bison Midstream systems, which have higher average gathering fees per Mcf. Additionally, the year-over-year increase in aggregate average throughput rate benefited from gas gathering agreement provisions which increased the average gas gathering fee per Mcf on our Grand River system beginning in January 2013. These contractual provisions helped offset the financial impact of the volume declines on the Grand River system. The impact of higher average gathering rates for the DFW Midstream system and the Bison Midstream system and the MVC contractual provisions for the Grand River system was partially offset by the lower average gathering fee per Mcf received on the Mountaineer Midstream system.
Gathering services and other fees increased during the year ended December 31, 2012, largely due to the contribution from the Grand River system. Gathering services and other fee revenue also reflects the impact of a decrease in aggregate average throughput rates we charge our customers. The aggregate average throughput rate for year ended December 31, 2012 was approximately $0.41 per Mcf, compared with approximately $0.52 per Mcf for the year ended December 31, 2011. The year-over-year decline was largely as a result of the lower average gathering fee per Mcf on our Grand River system. Gas gathering revenue for the Grand River system was $63.1 million in 2012, compared with $11.0 million in 2011.
Natural gas, NGLs and condensate sales and other. The increase in natural gas, NGLs and condensate sales and other for the year ended December 31, 2013, was primarily a result of the contribution from the Bison Midstream system, higher throughput volumes and the associated retainage on our DFW Midstream system, and an increase in the prices we were able to obtain for natural gas sales. Bison Midstream accounted for $38.2 million of the total increase in natural gas, NGLs and condensate sales and other for the year ended December 31, 2013.
Natural gas and condensate sales increased during the year ended December 31, 2012, primarily reflecting the contribution of the Grand River system. Revenue associated with condensate sales for the Grand River system was approximately $3.5 million in 2012, compared with $0.6 million in 2011.
Operation and Maintenance Expense. Operation and maintenance expense increased during the year ended December 31, 2013, largely as a result of expenses associated with the Bison Midstream and Mountaineer Midstream systems, a $4.3 million increase in power-related costs primarily for the DFW Midstream system, a $2.6 million increase in field employee costs, and a $1.6 million increase in carbon dioxide expenses primarily for the DFW Midstream system. The increase in operation and maintenance expense was partially offset by a $3.3 million decline in compressor lease and contract maintenance expenses primarily as a result of our purchase of previously leased compression assets in the first quarter of 2013. For the year ended December 31, 2013, operation and maintenance expense was $4.2 million for the Bison Midstream system and $2.4 million for the Mountaineer Midstream system.
During the year ended December 31, 2012, operation and maintenance expense increased largely as a result of Grand River system expenses incurred in 2012, partially offset by a decline in expenses for the DFW Midstream

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system. The decrease in operation and maintenance expense for the DFW Midstream system was primarily the result of a $1.3 million decline in compressor contractor services in 2012 due to the transition to in-house compressor services during the first quarter of 2012. This decrease was offset by an increase in property taxes as a result of the continued development of the DFW Midstream system. Operation and maintenance expense for the Grand River system was $26.5 million for the year ended December 31, 2012, compared with $3.9 million for the year ended December 31, 2011.
Cost of Natural Gas and NGLs. Cost of natural gas and NGLs represents the expenses associated with the percent-of-proceeds arrangements under which the Bison Midstream system sells natural gas purchased from our customers.
General and Administrative Expense. General and administrative expense increased during the year ended December 31, 2013, largely as a result of an increase in salaries, benefits and incentive compensation primarily as a result of increased head count and an increase in professional services expense. The Bison Midstream system accounted for $2.2 million and the Mountaineer Midstream system accounted for $0.8 million of general and administrative expense for the year ended December 31, 2013.
During the year ended December 31, 2012, general and administrative expense increased largely as a result of an increase of expenses due to the acquisition of the Grand River system in October 2011. This increase primarily reflects an increase in salaries and benefits due to increased headcount, an increase in insurance expenses primarily as a result of our growth, and an increase in professional services expenses. These increases were partially offset by a decrease in non-cash unit-based compensation from 2011 which included the initial recognition of expense associated with awards granted in 2010 and 2009 as well as an award modification in 2011 to remove a rate of return payout hurdle which also increased non-cash unit-based compensation expense.
Transaction Costs. Transaction costs were $2.8 million for the year ended December 31, 2013, of which $2.0 million related to the acquisition of the Mountaineer Midstream system and $0.8 million related to the acquisition of the Bison Midstream system. Transaction costs of $2.0 million in 2012 largely reflect costs associated with Summit Investments' acquisition of the Red Rock Gathering Company, LLC ("Red Rock") in October 2012. The Red Rock system was retained by Summit Investments. For the year ended December 31, 2011, transaction costs of $3.2 million were primarily related to the acquisition of the Grand River system.
Depreciation and Amortization Expense. Depreciation and amortization expense increased during the year ended December 31, 2013 largely due to recognizing depreciation and amortization from the Bison Midstream and Mountaineer Midstream systems. An increase in contract amortization for the Grand River system and assets placed into service in connection with the development of the DFW Midstream and Grand River systems also contributed to the increase. The Bison Midstream system accounted for $16.1 million of depreciation and amortization expense for the year ended December 31, 2013. The Mountaineer Midstream system also contributed $4.0 million to the increase in depreciation and amortization expense for the year ended December 31, 2013.
During the year ended December 31, 2012, depreciation and amortization expense increased largely due to the acquisition of the Grand River system in October 2011 and additional assets placed into service in connection with the development of the DFW Midstream system during 2011. Depreciation and amortization expense for the Grand River system was $23.1 million in 2012, compared with $3.2 million in 2011.
Interest Expense and Affiliated Interest Expense. The increase in interest expense during the year ended December 31, 2013, primarily reflects our issuance of $300.0 million of 7.50% senior notes in June 2013. Additionally, higher balances on our revolving credit facility beginning in May 2012 as well as an increase in commitment fees as a result of the May 2012 amendment and restatement of the revolving credit facility, which increased our borrowing capacity by $265.0 million and the June 2013 amendment and restatement, which increased our borrowing capacity by $50.0 million also contributed to the increase in interest expense.
The increase in interest expense during the year ended December 31, 2012, was primarily a result of the higher 2012 balances on the revolving credit facility that we obtained in May 2011. Affiliated interest expense for the year ended December 31, 2012 related to the $200.0 million promissory notes that we issued to the Sponsors in connection with the acquisition of the Grand River system in October 2011. The promissory notes were partially prepaid in May 2012 with the remaining balance repaid in July 2012.


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Non-GAAP Financial Measures
EBITDA, adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with accounting principles generally accepted in the United States of America ("GAAP"). We believe that the presentation of these non-GAAP financial measures provides useful information to investors in assessing our financial condition and results of operations.
Net income and net cash provided by operating activities are the GAAP financial measures most directly comparable to EBITDA, adjusted EBITDA and distributable cash flow. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Furthermore, each of these non-GAAP financial measures has limitations as an analytical tool because it excludes some but not all items that affect the most directly comparable GAAP financial measure. Some of these limitations include:
certain items excluded from EBITDA, adjusted EBITDA and distributable cash flow are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure;
EBITDA, adjusted EBITDA, and distributable cash flow do not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;
EBITDA, adjusted EBITDA, and distributable cash flow do not reflect changes in, or cash requirements for, our working capital needs;
although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA, adjusted EBITDA and distributable cash flow do not reflect any cash requirements for such replacements; and
our computations of EBITDA, adjusted EBITDA and distributable cash flow may not be comparable to other similarly titled measures of other companies.
We compensate for the limitations of EBITDA, adjusted EBITDA and distributable cash flows as analytical tools by reviewing the comparable GAAP financial measures, understanding the differences between the financial measures and incorporating these data points into our decision-making process.
EBITDA, adjusted EBITDA or distributable cash flow should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Because EBITDA, adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

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Net Income-Basis Non-GAAP Reconciliation. The following table presents a reconciliation of SMLP's net income to EBITDA, adjusted EBITDA and distributable cash flow for the periods indicated.
 
Year ended December 31,
 
2013
 
2012
 
2011
 
(In thousands)
Reconciliation of Net Income to EBITDA, Adjusted EBITDA and Distributable Cash Flow:
 
 
 
 
 
Net income (1)
$
43,636

 
$
41,726

 
$
37,951

Add:
 
 
 
 
 
Interest expense
19,173

 
12,766

 
3,054

Income tax expense
729

 
682

 
695

Depreciation and amortization expense
60,824

 
35,299

 
11,367

Amortization of favorable and unfavorable contracts
1,032