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:

As of December 31, 2013, our gathering systems and the basins they serve were as follows:

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:

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:

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

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:

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.

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:

Our Midstream Assets

Our midstream assets currently consist of four natural gas gathering systems:

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:

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).

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.

(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.

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.

(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.

The following table provides information regarding our DFW Midstream system as of December 31, 2013, except as noted.

(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

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.

(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

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,

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:

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:

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

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

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

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

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.