Summit Midstream Partners
Annual Report 2012

Plain-text annual report

Table of ContentsUNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549Form 10-K(Mark One)[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2012or[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period from toCommission file number: 001-35666Summit 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 registeredCommon Units New York Stock ExchangeIndicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.o Yes x NoIndicate 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 NoIndicate 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 of1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject tosuch filing requirements for the past 90 days. x Yes o NoIndicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data Filerequired 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 suchshorter period that the registrant was required to submit and post such files).x Yes o NoIndicate 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 ofthis Form 10-K or any amendment to this Form 10-K. oIndicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reportingcompany. 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 oNon-Accelerated Filer x (Do not check if a smaller reporting company) Smaller Reporting Company oIndicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes x NoThe registrant completed its IPO in October 2012. As such, it cannot calculate the aggregate market value of its common units held by non-affiliates as of the last business day of its most recently completed second fiscal quarter because there was no established public trading market forits common units as of such date.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, 2013Common Units 24,412,427 unitsSubordinated Units 24,409,850 unitsGeneral Partner Units 996,320 unitsTABLE OF CONTENTSPART I 1Item 1.Business.1Item 1A.Risk Factors.19Item 1B.Unresolved Staff Comments.46Item 2.Properties.47Item 3.Legal Proceedings.47Item 4.Mine Safety Disclosures.47 PART II 48Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases ofEquity Securities.48Item 6.Selected Financial Data.50Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations.53Item 7A.Quantitative and Qualitative Disclosures about Market Risk.70Item 8.Financial Statements and Supplementary Data.70Item 9.Changes in and Disagreements With Accountants on Accounting and Financial Disclosure Matters.71Item 9A.Controls and Procedures.71Item 9B.Other Information.71 PART III 72Item 10.Directors, Executive Officers and Corporate Governance.72Item 11.Executive Compensation.77Item 12.Security Ownership of Certain Beneficial Owners and Management and Related StockholderMatters.83Item 13.Certain Relationships and Related Transactions, and Director Independence.85Item 14.Principal Accounting Fees and Services.88 PART IV 89Item 15.Exhibits, Financial Statement Schedules.89iTable of ContentsFORWARD-LOOKING STATEMENTSInvestors are cautioned that certain statements contained in this report as well as in periodic press releases and some oral statements madeby our officials during our presentations are “forward-looking” statements. Forward-looking statements include, without limitation, anystatement 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 conditionalverbs such as “may,” “will,” “should,” “would,” and “could.” In addition, any statement concerning future financial performance (includingfuture 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 ofrisks and uncertainties, many of which are beyond the control of our management team. All forward-looking statements in this report andsubsequent written and oral forward-looking statements attributable to us, or to persons acting on our behalf, are expressly qualified in theirentirety by these risks and uncertainties. These risks and uncertainties include, among others:•changes in general economic conditions;•fluctuations in 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 ourassets;•failure or delays by our customers in achieving expected production in their natural gas projects;•competitive conditions in our industry and their impact on our ability to connect natural gas supplies to our gathering andcompression assets or systems;•actions or inactions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transportersand customers;•our ability to consummate acquisitions, successfully integrate the acquired businesses, realize any cost savings and other synergiesfrom any acquisition;•the ability to attract and retain key management personnel;•changes in the availability and cost of capital;•the availability, terms and cost of downstream transportation services;•operating hazards, natural disasters, accidents, weather-related delays, casualty losses and other matters beyond our control;•timely receipt of necessary government approvals and permits, our ability to control the costs of construction, including costs ofmaterials, labor and right-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 existing and future 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 significantreduction in the market price of our common units. 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 theserisks 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.iiTable of ContentsGLOSSARY OF TERMSadjusted EBITDA: EBITDA plus non-cash compensation expense and adjustments related to minimum volume commitment shortfallpaymentsAMI: area of mutual interestcondensate: a natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbonfractionsdistributable cash flow: adjusted EBITDA plus cash interest income, less cash paid for interest expense and income taxes andmaintenance capital expendituresdry gas: a gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removedthrough processingEBITDA: net income, plus interest expense, income tax expense, and depreciation and amortization expense, less interest income andincome tax benefitend users: the ultimate users and consumers of transported energy productsMcf: one thousand cubic feetMMBtu: one million British Thermal UnitsMMcf: one million cubic feetMMcf/d: one million cubic feet per dayMVC: minimum volume commitmentNGLs: natural gas liquids; the combination of ethane, propane, normal butane, iso-butane and natural gasolines that when removed fromnatural gas become liquid under various levels of higher pressure and lower temperatureNYMEX: New York Mercantile Exchangeplay: a proven geological formation that contains commercial amounts of hydrocarbonsreceipt point: the point where production is received by or into a gathering system or transportation pipelineresidue gas: the natural gas remaining after being processed or treatedtailgate: refers to the point at which processed natural gas and NGLs leave a processing facility for end-use marketsTcf: one trillion cubic feetthroughput volume: the volume of natural gas transported or passing through a pipeline, plant or other facility during a particular periodwellhead: the equipment at the surface of a well used to control the well's pressure; also, the point at which the hydrocarbons and water exitthe groundiiiTable of ContentsPART IItem 1. Business.Summit Midstream Partners, LP ("SMLP") is a Delaware limited partnership that completed its initial public offering ("IPO") on October3, 2012 to become a publicly traded entity. Summit Midstream Partners, LLC ("Summit Investments") is a Delaware limited liabilitycompany 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, refer collectively to Summit Investments and itssubsidiaries. 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 partnerconveyed its interest in Summit Holdings to SMLP; and Summit Investments conveyed its remaining interest in Summit Holdings toSMLP. Therefore, the historical financial statements contained in this Form 10-K reflect the assets, liabilities and operations ofSummit Investments (excluding the results of operations of assets outside of Summit Holdings that were retained by SummitInvestments) for periods ending before October 3, 2012 and the assets, liabilities and operations of SMLP for periods beginning onor after October 3, 2012. 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 GEEnergy Financial Services, Inc. References in this Form 10-K to our "Sponsors" refer collectively to Energy Capital Partners and GEEnergy Financial Services.OverviewSMLP is a growth-oriented limited partnership focused on owning and operating midstream energy infrastructure assets that are strategicallylocated in the core producing areas of unconventional resource basins, primarily shale formations, in North America. We provide natural gasgathering and compression services pursuant to long-term, fee-based natural gas gathering agreements with our customers. Our results aredriven primarily by the volumes of natural gas that we gather and compress across our systems. During the year ended December 31, 2012,we generated approximately 90% of our revenue from fee-based gathering services that we provided to our customers. We currently operatein two unconventional resource basins:•the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado;and•the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas.The Grand River system services our customers operating in the Piceance Basin and the DFW Midstream system services our customersoperating in the Fort Worth Basin. As of December 31, 2012, these gathering systems had approximately 399 miles of pipeline and 147,600horsepower of compression. During 2012, these systems gathered an average of approximately 929 MMcf/d of natural gas, of whichapproximately 62% was delivered to a third-party natural gas processing facility.We generate a substantial majority of our revenue under long-term, fee-based natural gas gathering agreements with remaining terms thatrange from six years to 24 years. The fee-based nature of these agreements enhances the stability of our cash flows by limiting our directcommodity price exposure. Our customers include affiliates and/or subsidiaries of some of the largest natural gas producers in NorthAmerica, such as:•Bill Barrett Corporation ("Bill Barrett");•Carrizo Oil & Gas, Inc. ("Carrizo");•Chesapeake Energy Corporation ("Chesapeake");•Encana Corporation ("Encana");•EOG Resources, Inc. ("EOG");•Exxon Mobil Corporation ("Exxon Mobil");•TOTAL, S.A. ("TOTAL"); and•WPX Energy, Inc. ("WPX Energy").1Table of ContentsA significant percentage of our revenue is attributable to three producer customers and one natural gas marketer. For the year endedDecember 31, 2012, customers that accounted for 10% or more of total revenues were Carrizo, Chesapeake and Encana.Substantially all of our gas gathering agreements include areas of mutual interest ("AMIs"). Areas of mutual interest require that anyproduction from natural gas wells drilled by our customers within the AMI be shipped on our gathering systems. Our AMIs coverapproximately 330,000 acres in the aggregate and have remaining terms that range from six years to 24 years.In addition, substantially all of our gas gatherings agreements include minimum volume commitments ("MVCs"). A minimum volumecommitment contractually obligates our customers to ship a minimum quantity of natural gas or make payments to cover the shortfall ofnatural gas not shipped, either on a monthly or annual basis. We have designed our minimum volume commitment provisions to ensurethat we will generate a certain amount of revenue from each customer over the life of the respective gas gathering agreement, whether bycollecting gathering fees on actual throughput or from cash payments to cover any minimum volume commitment shortfall. As of December31, 2012, we had remaining minimum volume commitments totaling 2.4 Tcf with original terms that range from seven years to 15 years.Our minimum volume commitments have a weighted-average remaining life of 11.1 years (assuming minimum throughput volume for theremainder of the term) and average approximately 629 MMcf/d through 2020.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 strategic partnerships with large producers to provide midstream services for their upstreamdevelopment projects. We also intend to expand our operations and diversify our geographic footprint through asset acquisitions from thirdparties and Summit Investments, although Summit Investments has no obligation to offer any assets to us in the future.Our midstream assets currently consist of two natural gas gathering systems, the Grand River system in western Colorado and the DFWMidstream system in north-central Texas.Grand River SystemIn October 2011, we acquired certain natural gas gathering pipeline, dehydration and compression assets in the Piceance Basin in westernColorado from Encana Oil & Gas (USA) Inc., a subsidiary of Encana for $590.2 million. We refer to these assets as the Grand River system.As of December 31, 2012, the Grand River system comprised approximately 289 miles of pipeline and 97,500 horsepower of compression.It is primarily located in Garfield County, the largest natural gas producing county in Colorado and is composed of three distinct gatheringsystems that service producers operating in: (i) the Mamm Creek Field, (ii) the South Parachute Field, and (iii) the Orchard Field. Natural gasgathered on these three systems 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. For the year ended December 31,2012, the Grand River system gathered an average of approximately 575 MMcf/d from six producers, including Encana as the anchorcustomer.The Grand River system primarily gathers natural gas produced by our customers from the liquids-rich Mesaverde formation within thePiceance Basin. The Mesaverde is a shallow, tight sands geologic formation that producers have targeted with directional drilling for severaldecades. We also gather natural gas from our customers' wells targeting the deeper Mancos and Niobrara shale formations. Over the last twoyears, our customers have completed numerous horizontal wells targeting the emerging Mancos and Niobrara shale formations. Theseformations generally have higher initial production rates and lower Btu content than Mesaverde wells. Based on our customers' currentdrilling activities, we anticipate that the majority of our near-term throughput on the Grand River system will continue to originate from theMesaverde formation.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. To the extent natural gas prices increase from current levels, we expect that our customers willaccelerate drilling activities targeting the Mancos and Niobrara shale formations. Furthermore, increased production from the Mancos andNiobrara shale formations will provide an opportunity for us to construct a new medium-pressure gathering system which will separateliquids-rich natural gas from dry natural gas production, increase total throughput capacity and allow for additional liquids-rich natural gas tobe shipped on the Grand River system.DFW Midstream SystemIn September 2009, we acquired approximately 17 miles of pipeline and 2,500 horsepower of electric-drive compression in north-centralTexas from Energy Future Holdings Corp. ("Energy Future Holdings") and2Table of ContentsChesapeake. We refer to these assets as the DFW Midstream system. Since the initial acquisition, we have expanded the DFW Midstreamsystem by adding pipeline and installing incremental compression horsepower. As of December 31, 2012, the DFW Midstream system hadapproximately 110 miles of pipeline that connected 64 pad sites and had 50,100 horsepower of compression. The DFW Midstream systemcurrently 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 inLouisiana. For the year ended December 31, 2012, the DFW Midstream system gathered an average of approximately 355 MMcf/d fromeight producers, including Chesapeake as the anchor customer.The DFW Midstream system benefits from its location in southeastern Tarrant County, Texas, which is commonly referred to as the core ofthe Barnett Shale. Based on peak month average daily production rates sourced from the Railroad Commission of Texas as of June 2012,this area contains the most prolific wells in the Barnett Shale. For example, the two largest and four of the 10 largest wells drilled in theBarnett Shale (based on initial production) 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 drillingtechniques from pad sites already connected or identified to be connected in our areas of mutual interest. Given the urban nature ofsoutheastern Tarrant County, we expect that the majority of future natural gas drilling in this area will occur from existing pad sites. As aresult, we believe we will be able to increase throughput and cash flows with minimal additional capital expenditures.Organization and Results of OperationsSMLP was formed in May 2012 in anticipation of our initial public offering which closed on October 3, 2012. On October 3, 2012,immediately prior to the closing of the IPO, Summit Investments conveyed an interest in Summit Holdings to our general partner as acapital contribution; our general partner conveyed its interest in Summit Holdings to SMLP; and Summit Investments conveyed itsremaining interest in Summit Holdings to SMLP. We issued 14,375,000 common units to the public in the IPO, which included the exerciseof the underwriters’ right to purchase additional common units and represented a 28.9% limited partner interest in SMLP. At the time of theIPO, Summit Investments' partnership interest in SMLP was represented by: (i) 10,029,850 common units, or a 20.1% limited partnerinterest, (ii) 24,409,850 subordinated units, or a 49.0% limited partner interest, and (iii) a 2% general partner interest.Summit Investments, which owns and controls our general partner, was formed in 2009 by members of our management team and EnergyCapital Partners. In August 2011, Energy Capital Partners sold a noncontrolling interest in Summit Investments to GE Energy FinancialServices. Due to its ownership interest in Summit Investments and its representation on Summit Investments' board of managers, EnergyCapital Partners controls our general partner and its activities, and as a result, SMLP.We manage our business and analyze our results of operations as a single segment. Our financial results are primarily driven by thevolumes of natural gas that we gather across our systems and our management of operations and maintenance expense. We use a varietyof financial and operational metrics to analyze our performance.3Table of ContentsThe following table presents certain operating and financial measures for the periods indicated: Year ended December 31, 2012 2011 2010 (Dollars in thousands)Statement of Operations Data: Total revenue$165,499 $103,552 $31,676Total costs and expenses110,334 61,864 23,412Net income41,726 37,951 8,172 Other Financial and Operating Data: EBITDA$90,656 $53,363 $12,353Adjusted EBITDA103,300 56,803 12,353Capital expenditures76,698 78,248 153,719Acquisition expenditures— 589,462 —Distributable cash flow88,492 50,980 11,726 Aggregate average throughput (MMcf/d)929 431 136For additional information on the above data as well as the reconciliations of EBITDA, adjusted EBITDA and distributable cash flow to netincome and net cash flows provided by operating activities, see Item 7. Management's Discussion and Analysis of Financial Condition andResults of Operations ("MD&A").Industry OverviewGeneralThe midstream segment of the natural gas industry is the link between the exploration and production of natural gas from the wellhead andthe delivery of the natural gas and its other components to end-use markets. Companies within this industry create value at various stagesalong 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 nextintermediate stage of the value chain. The following diagram illustrates the assets commonly found along the natural gas value chain:4Table of ContentsMidstream ServicesThe 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 systemsdirectly connect to wellheads, pad sites or other receipt points in the production area. These gathering systems transport natural gas from thewellhead to downstream pipelines or a central location for treating and processing. A large gathering system may involve thousands of milesof gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of naturalgas at different pressures and scalable to allow for additional production and well connections without significant incremental capitalexpenditures.Compression. Gathering systems are operated at design pressures that enable the maximum amount of production to be gathered fromconnected wells. Through a mechanical process known as compression, volumes of natural gas at a given pressure are compressed to asufficiently higher pressure, thereby allowing those volumes to be delivered to the market via a higher pressure downstream pipeline. Sincewells produce at progressively lower field pressures as they age, it becomes necessary to add additional compression over time to maintainthroughput across the gathering system.Treating and Dehydration. Another process in the midstream value chain is treating and dehydration. Treating and dehydration involvesthe removal of impurities such as water, carbon dioxide, nitrogen and hydrogen sulfide, which may be present when natural gas is producedat the wellhead. These impurities must be removed for the natural gas to meet the specifications for transportation on long-haul intrastate andinterstate 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 otherNGLs, which are heavier hydrocarbons that are found in some natural gas streams. Even after treating and dehydration, some natural gas isnot suitable for long-haul intrastate and interstate pipeline transportation or commercial use because it contains NGLs and condensate. Thisnatural gas, referred to as liquids-rich natural gas, must also be processed to remove these heavier hydrocarbon components. NGLs not onlyinterfere with pipeline transportation, but are also valuable commodities once removed from the natural gas stream. The removal andseparation 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 andindustrial 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 arestored, transported and marketed to end-use markets. Each pipeline system typically has storage capacity located both throughout thepipeline network and at major market centers to help temper seasonal demand and daily supply-demand shifts.Contractual ArrangementsMidstream natural gas services, other than transportation and storage, are usually provided under contractual arrangements that vary in theamount 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 andcompressed at the wellhead and an additional fee per unit of natural gas treated or processed at its facility. As a result, the service providerbears no direct commodity price risk exposure.Percent-of-Proceeds. Under these arrangements, the service provider typically remits to the producers either a percentage of the proceedsfrom 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 arrangementsexpose the gatherer/processor to commodity price risk, as the revenues from the contracts directly correlate with the fluctuating price ofnatural gas and NGLs.Keep-Whole. Under these arrangements, the service provider keeps 100% of the NGLs produced, and the processed natural gas, or valueof the natural gas, is returned to the producer. Since some of the natural gas is used and removed during processing, the processorcompensates the producer for the amount of natural gas used5Table of Contentsand removed in processing by supplying additional natural gas or by paying an agreed-upon value for the natural gas utilized. Thesearrangements have the highest commodity price exposure for the processor because the costs are dependent on the price of natural gas andthe revenues are based on the price of NGLs.Two typical forms of contracts utilized in the 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 customersgenerally pay a demand or capacity reservation fee based on the amount of capacity being reserved, regardless of whether the capacity isused, plus a usage fee based on the amount of natural gas transported. Firm storage contracts involve the reservation of a specific amount ofstorage capacity, including injection and withdrawal rights, and generally include a capacity reservation charge based on the amount ofcapacity being reserved plus an injection and/or withdrawal fee.Interruptible. Interruptible service is typically short-term in nature and is generally used by customers that either do not need firm service orhave been unable to contract for firm service. These customers pay only for the volume of gas actually transported or stored. The obligation toprovide this service is limited to available capacity not otherwise used by firm customers, and as such, customers receiving services underinterruptible contracts are not assured capacity on the pipeline or at the storage facility.Business StrategiesOur principal business strategy is to increase the amount of cash distributions we make to our unitholders over time. Our plan for executingthis strategy includes the following key components:•Pursuing accretive acquisition opportunities from Summit Investments. We intend to pursue opportunities to expand ourasset base by acquiring midstream infrastructure assets currently owned and operated by Summit Investments. In addition to itssignificant ownership interest in us, Summit Investments also owns and controls crude oil, natural gas and water-relatedmidstream assets in service and under development in geographic areas outside of our current operations, including the BakkenShale Play in North Dakota and the DJ Niobrara Shale Play in Colorado. We believe that Summit Investments' economic interest inus incentivizes it to offer us opportunities to acquire these assets in the future under accretive terms.•Diversifying our asset base by expanding our midstream service offerings and exploring acquisition and developmentopportunities in various geographic areas. While our natural gas gathering operations in the Piceance Basin and the BarnettShale currently represent our core business, we intend to diversify into other midstream services such as natural gas processingand crude oil gathering, through both greenfield development projects and acquisitions. We also intend to diversify our operationsinto other geographic regions through acquisitions and development of new anchor customer relationships. We and our Sponsorsare frequently involved in discussions with third parties regarding the purchase of natural gas and crude oil midstream energyinfrastructure assets. Working together with our Sponsors, we intend to continue to evaluate opportunities to acquire or develop othermidstream energy infrastructure assets that complement our existing business and allow us to leverage our asset base and ourmanagement team's development and industry expertise.•Capitalizing on organic growth opportunities. We believe that our existing gathering systems provide us with significant organicexpansion opportunities. We intend to leverage our management team's expertise in constructing, developing and optimizingmidstream infrastructure assets to grow our business through organic development projects that are designed to extend ourgeographic reach, diversify our customer base, expand our midstream service offerings, increase the number of our natural gasreceipt points and maximize volume throughput.•Increasing throughput volumes on our existing systems. We intend to continue to focus on maximizing the utilization of ourassets by increasing volume throughput from existing customers and connecting new customers to our systems. For example, weincreased the capacity of the DFW Midstream system from 410 MMcf/d to over 450 MMcf/d with the installation of a new compressorunit that came on line in January 2013. In addition, we designed the DFW Midstream system to benefit from incremental volumesarising from high-density, infill drilling on existing pad sites that are already connected to the our gathering system and as suchwould not require significant additional capital expenditures.•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-6Table of Contentsbased arrangements. Our midstream services are almost exclusively provided under long-term, fee-based contracts with originalterms ranging from 10 years to 25 years. We believe that our focus on fee-based revenues with minimal direct commodity exposureis essential to maintaining stable cash flows and increasing our quarterly distributions over time.•Partnering with producers to provide midstream services for their development projects in high-growth, unconventionalresource plays. We seek to promote commercial relationships with established and well-capitalized producers, who are willing toserve as an anchor customer and commit to long-term volumes and AMIs. We will continue to pursue partnership opportunities withestablished producers to develop new infrastructure in unconventional resource basins that we believe will complement our existingmidstream assets or enhance our overall business by facilitating our entry into new basins. These opportunities generally consist ofa strategic acreage position in an unconventional resource play and represent assets that are well-positioned for acceleratedproduction growth but have minimal existing midstream energy infrastructure to support such growth. For example, we havesecured agreements covering AMIs from certain of our customers covering all of their natural gas production from approximately230,000 acres in the Piceance Basin where Encana serves as our anchor customer and 100,000 acres in the Barnett Shale whereChesapeake serves as our anchor customer. We have been successful with this strategy and will continue to pursue similaropportunities that utilize our management team's experience in constructing, developing and operating large scale midstreaminfrastructure.Competitive StrengthsWe believe that we will be able to execute the components of our principal business strategy successfully because of the followingcompetitive strengths:Strategically located assets in core areas of prolific unconventional basins supported by existing partnerships with largeproducers to provide midstream services for their development projects. Our midstream energy infrastructure assets arestrategically positioned within the core areas of two established unconventional resource plays. The formations in the basins served by ourassets have relatively low drilling and completion costs. We believe that producers will continue their drilling and completion activities in thecore areas of unconventional natural gas shale basins even if natural gas prices do not increase significantly from current levels because thereturn economics associated with core-area wells remain favorable in lower pricing environments compared with more marginal areas ofproduction. We believe that continued drilling activity in these basins positions us to pursue attractive growth opportunities by furtherdeveloping and optimizing our systems and developing or acquiring complementary systems within our geographic areas of operation.•Grand River system. The Grand River system is located in the Piceance Basin in western Colorado and currently serves producerstargeting the liquids-rich Mesaverde formation. It is optimally located for expansion to gather production from the emerging Mancosand Niobrara shale formations. In response to our customers' recent drilling activities, we have begun constructing a new medium-pressure gathering system to service anticipated future higher pressure gas production from the Mancos and Niobrara shaleformations.•DFW Midstream system. The DFW Midstream system is primarily located in southeastern Tarrant County, currently the largestnatural gas producing county in Texas. We consider this area to be the core of the core of the Barnett Shale because of the quality ofthe geology and the high production profile of the wells drilled to date. We believe that the areas of mutual interest underpinning oursystem are substantially undeveloped compared with other areas in the Barnett Shale due to the lack of historical gatheringinfrastructure. Our areas of mutual interest and our system footprint provide us with a competitive advantage to add additionalproducers and incremental volumes in this core area of the Barnett Shale at a competitive capital cost.Fee-based revenues underpinned by long-term contracts with minimum volume commitments. A substantial majority of ourrevenue for the year ended December 31, 2012 was generated under long-term, fee-based gas gathering agreements. Several of ourcustomers are among the largest producers in each of our areas of operation. In the Piceance Basin, we have a 25-year area of mutualinterest agreement covering approximately 187,000 acres and 1.4 Tcf of remaining MVCs with Encana through 2026. Together with ourother gas gathering agreements with our other customers operating in the Piceance Basin, we have areas of mutual interest coveringapproximately 230,000 acres and remaining minimum volume commitments of approximately 2.0 Tcf through 2026. In the Barnett Shale,we have a 20-year area of mutual interest with Chesapeake and Total covering approximately 95,000 acres and 287 Bcf of remaining MVCsthrough 2020. Together with our other gas gathering agreements with our other7Table of Contentscustomers operating in the Barnett Shale, we have areas of mutual interest covering approximately 100,000 acres and remaining minimumvolume commitments of approximately 372 Bcf through 2020. We believe that long-term, fee-based gas gathering agreements enhances thestability of our cash flows by limiting our direct commodity price exposure.Capital structure and financial flexibility. At December 31, 2012, we had $199.2 million of indebtedness and $350.8 million ofborrowing capacity available to us under our $550.0 million revolving credit facility. Under the terms of the revolving credit facility, our totalleverage ratio (net debt divided by EBITDA) was approximately 1.8:1 at December 31, 2012. We believe our borrowing capacity and our abilityto access private and public debt and equity capital will provide us with the necessary financial flexibility to execute our growth and expansionstrategy.Experienced management team with proven record of asset acquisition, construction, development, operation and integrationexpertise. Our executive management team has an average of 18 years of energy experience and a proven track record of identifying andconsummating significant acquisitions in addition to partnering with major producers to construct and develop midstream energyinfrastructure. As evidenced by our current business, our management team has demonstrated particular expertise in constructing new, aswell as developing and optimizing underutilized, midstream assets, which are key elements of our growth strategy. We employ engineering,construction and operations teams that have significant experience in designing, constructing and operating large midstream energyinfrastructure.Relationships with large and committed financial sponsors. Our Sponsors are experienced energy investors with proven track recordsof making substantial, long-term investments in high-quality energy assets. We believe the relationship with our Sponsors will be acompetitive advantage, as they bring not only significant financial and management experience, but also numerous relationships throughoutthe energy industry that we believe will benefit us as we seek to grow our business. In addition, we believe that our Sponsors will remainmotivated to promote and support the successful execution of our business strategies due to their ownership of a substantial portion of ourcommon units and all of our subordinated units.In October 2012, Summit Investments, which owns and controls our general partner, acquired a natural gas gathering and processingsystem that gathers and processes production from the Piceance and Uinta basins in Colorado and Utah for $207.0 million. In February2013, Summit Investments acquired a midstream energy company that owns, operates and is developing various natural gas gathering andprocessing assets along with crude oil and water gathering assets in the Bakken and DJ Niobrara shale plays for $513.0 million. SummitInvestments' purchase of these midstream assets was funded via a cash contribution from Energy Capital Partners. While these assetshave not been contributed to SMLP and Summit Investments is not obligated to sell these assets to SMLP, we believe they may represent afuture opportunity for execution of our business strategy.Our Midstream AssetsOur midstream assets currently consist of two natural gas gathering systems, the Grand River system in western Colorado and the DFWMidstream system in north-central Texas. We earn revenue primarily from long-term, fee-based gas gathering agreements with some of thelargest and most active producers in our areas of operation. The fee-based nature of these agreements enhances the stability of our cashflows by limiting our direct commodity price exposure. The significant features of our gas gathering agreements and the gathering systems towhich they relate are discussed in more detail below.Areas of Mutual InterestOur gas gathering agreements contain areas of mutual interest. The areas of mutual interest generally have original terms that range from10 years to 25 years and require that any production by our customers within the areas of mutual interest will be shipped on our gatheringsystems. Our customers do not have leases that currently cover our entire areas of mutual interest in the Piceance Basin and Barnett Shalebut, to the extent our customers lease additional acreage in the future within those areas of mutual interest, natural gas produced by ourcustomers from that leased acreage will be gathered by the Grand River and DFW Midstream systems.Under certain of our gas gathering agreements, we have agreed to construct pipeline laterals to connect our gathering systems to pad siteslocated within the area of mutual interest. If we choose not to participate in a discretionary opportunity presented by a customer, the customermay, 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 area of mutual interest.8Table of ContentsMinimum Volume CommitmentsOur gas gathering agreements contain MVCs pursuant to which our customers guarantee to ship a minimum volume of natural gas on ourgathering systems, or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. The originalterms of the MVCs range from seven to 15 years. In addition, certain of our customers have an aggregate MVC, which is a total amount ofnatural gas that the customer has agreed to ship on our gathering systems (or an equivalent monetary amount) over the MVC term. In thesecases, once a customer achieves its aggregate MVC, any remaining future MVCs will terminate and the customer will then simply pay theapplicable 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 endof that contract month or year, as applicable. The amount of the shortfall payment is based on the difference between the actual throughputvolume shipped for the applicable period and the MVC for the applicable period, multiplied by the applicable gathering fee. To the extent that acustomer's actual throughput volumes are above or below its MVC for the applicable period, however, many of our gas gathering agreementscontain provisions that can operate to reduce or delay the cash flows that we expect to receive from our MVCs. These provisions include thefollowing:•To the extent that a customer's throughput volumes are less than its MVC for the applicable period and the customer makes ashortfall payment, it may be entitled to an offset in one or more subsequent periods to the extent that its throughput volumes insubsequent periods exceed its MVC for those periods. In such a situation, we would not receive gathering fees on throughput inexcess of a customer's monthly or annual MVC (depending on the terms of the specific gas gathering agreement) to the extent thatthe 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 excessthroughput against its aggregate MVC, thereby reducing the period for which its annual MVC applies. For example, one of our DFWMidstream customers has a contracted MVC term from October 2010 through September 2017. However, this customer hasregularly shipped volumes in excess of its MVCs. In the fourth quarter of 2012, this customer satisfied the requirements of itsaggregate MVC, thereby reducing the period for which its MVC applies from eight years to less than three years. As a result of thismechanism, the weighted-average remaining period for which our MVCs apply is less than the weighted average of the originalstated 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 creditingmechanism that allows the customer to build a bank of credits that it can utilize in the future to reduce shortfall payments owed insubsequent periods, subject to expiration if there is no shortfall in subsequent periods. The period over which this credit bank can beapplied to future shortfall payments varies, depending on the particular gas gathering agreement.Grand River SystemIn October 2011, we acquired the Grand River system from Encana for $590.2 million. The Grand River system is primarily located inGarfield County, the largest natural gas producing county in Colorado, and comprises approximately 289 miles of three inch to 24 inchdiameter pipeline and approximately 97,500 horsepower of compression. The Grand River system gathers natural gas from the Mesaverdeformation and the Mancos and Niobrara shale formations located within the Piceance Basin. All of the natural gas gathered on the GrandRiver system is discharged to third-party pipelines that deliver to Enterprise's 1.7 Bcf/d processing facility located in Meeker, Colorado.The Grand River system is primarily a low-pressure gathering system that was originally designed to gather natural gas produced fromtraditional vertical wells targeting the liquids-rich Mesaverde formation. As of December 31, 2012, our largest Grand River customer,Encana, had 1,822 wells on 379 pad sites connected to our gathering system. We also receive natural gas from other customers at ninecentral receipt points on the Grand River system. We expect to continue to pursue additional volumes on the low-pressure system to morefully utilize the existing throughput capacity.In connection with our acquisition of the Grand River system, we entered into a contractual relationship with Encana related to thedevelopment of midstream infrastructure to support Encana's emerging Mancos and Niobrara shale development. In addition to theunderpinning provided by our gas gathering agreements, Encana's drilling program in the Mamm Creek and South Parachute fields issupported by its joint venture with Nucor Corporation, which specifies a minimum number of Mesaverde wells to be drilled.9Table of ContentsAs of December 31, 2012, the Grand River system had aggregate throughput capacity of 885 MMcf/d. For the year ended December 31,2012, it gathered an average of approximately 575 MMcf/d from the Mamm Creek, South Parachute and Orchard fields in the area aroundRifle, Colorado.The following table provides information regarding our Grand River system as of December 31, 2012, except as noted.Gathering system Approximatelength (Miles) Approximatenumber of wellsserviced (1) Compression(Horsepower) Throughputcapacity(MMcf/d) (2) Averagethroughput(MMcf/d) (3) Approximateareas of mutualinterest (Acres) RemainingMVCs (Bcf)Mamm Creek 186 1,375 60,180 600 434 174,000 1,105South Parachute 39 146 12,168 75 83 17,000 —Orchard 64 301 25,152 210 58 39,000 875Total Grand Riversystem 289 1,822 97,500 885 575 230,000 1,980__________(1) Excludes wells connected to nine central receipt points that represent an aggregate average throughput of 256 MMcf/d for the year endedDecember 31, 2012.(2) Represents throughput capacity for compressor stations located within a particular area of mutual interest. In 2012, production in the SouthParachute field exceeded the amount of throughput capacity in the South Parachute AMI. As a result, this excess volume was compressed anddischarged by compressor stations in the Orchard system.(3) For the year ended December 31, 2012.Mamm Creek. The Mamm Creek system is underpinned by long-term, fee-based gas gathering and compression agreements with BillBarrett, Encana, Ursa Resources and WPX Energy. These agreements include minimum volume commitments with original terms rangingfrom 10 to 15 years and areas of mutual interest with original terms ranging from 10 years to 25 years. As of December 31, 2012, these gasgathering agreements had remaining minimum volume commitments totaling approximately 1.1 Tcf over the next 14 years, an average ofapproximately 205 MMcf/d through 2026, and areas of mutual interest covering approximately 174,000 acres. For the year ended December31, 2012, this system gathered approximately 434 MMcf/d. Additionally, because certain customers produced less natural gas than theirminimum volume commitments for the Mamm Creek Field, we billed and subsequently collected approximately $9.7 million of minimumvolume commitment shortfall payments during 2012.10Table of ContentsSouth Parachute. The South Parachute system is underpinned by a 25-year, fee-based gas gathering agreement with Encana and areas ofmutual interest with an original term of 25 years. As of December 31, 2012, the area of mutual interest covered approximately 17,000 acres.For the year ended December 31, 2012, this system gathered approximately 83 MMcf/d.Orchard. The Orchard system is underpinned by a 25-year, fee-based gas gathering agreement with Encana and an area of mutual interestwith an original term of 25 years. As of December 31, 2012, this gas gathering agreement had remaining minimum volume commitmentstotaling approximately 875 Bcf over the next 14 years, an average of approximately 162 MMcf/d through 2026, and areas of mutual interestcovering approximately 39,000 acres. For the year ended December 31, 2012, this system gathered approximately 58 MMcf/d. Additionally,because Encana produced less natural gas than its 2012 minimum volume commitment, we billed and subsequently collectedapproximately $4.8 million of minimum volume commitment shortfall payments for fiscal 2012.DFW Midstream SystemThe DFW Midstream system is primarily located within southeastern Tarrant County, Texas, which resides within the Fort Worth Basin andincludes the Barnett Shale geologic formation. We consider southeastern Tarrant County to be the core of the core of the Barnett Shalebecause it contains the most prolific wells, including the two largest and four of the 10 largest wells drilled in the Barnett Shale (based oninitial production) according to data sourced from the Railroad Commission of Texas as of June 2012. The DFW Midstream system includesgathering lines ranging from 8 inches to 30 inches in diameter and is located along existing electric transmission corridors and under bothprivate and public property. The system currently has five primary interconnections with third-party, intrastate pipelines that enable us toconnect our customers with the major natural gas market hubs of Waha, Carthage and Katy in Texas and Perryville and Henry Hub inLouisiana.11Table of ContentsThe following table provides information regarding our DFW Midstream system as of December 31, 2012, except as noted.Gathering system Approximatelength (Miles) Approximatenumber of wellsserviced Compression(Horsepower) Throughputcapacity(MMcf/d) Average throughput (MMcf/d)(1) Approximate areas of mutualinterest (Acres) RemainingMVCs (Bcf)DFW Midstream 110 312 50,100 410 355 100,000 372__________(1) For the year ended December 31, 2012.The DFW Midstream system is underpinned by eight long-term, fee-based gas gathering agreements with Atlas Energy, Beacon E&P,Carrizo, Chesapeake, EOG, Exxon Mobil, TOTAL and Vantage. As of December 31, 2012, these gas gathering agreements had remainingMVCs totaling approximately 372 Bcf and, through 2020, average approximately 127 MMcf/d. In addition, these gas gathering agreementshave areas of mutual interest that cover approximately 100,000 acres through 2030. We retain a small fixed percentage of the natural gas thatwe receive at the receipt points to offset the costs we incur to operate our electric-drive compressors.We have owned and operated the DFW Midstream system since September 2009 when we acquired it from Energy Future Holdings andconcurrently acquired certain complementary pipeline and other related gathering system assets from Chesapeake. We simultaneouslyentered into a long-term gas gathering agreement with Chesapeake as our anchor customer that included a 20-year area of mutual interestcovering approximately 95,000 acres and a 10-year MVC totaling approximately 450 Bcf.We continue to develop the DFW Midstream system to extend our gathering reach, diversify our customer base, increase our receipt pointsand maximize throughput. Since the acquisition, we have expanded this system by adding pipeline, continuing to connect additional padsites located within our areas of mutual interest, and expanding the throughput capacity by installing additional electric-drive compression.For the year ended December 31, 2012, the DFW Midstream system had average throughput of approximately 355 MMcf/d. As of December31, 2012, the DFW Midstream system included approximately 110 miles of low- and high-pressure gathering lines and 50,100 horsepower ofcompression. As of December 31, 2012, approximately 312 wells on 64 pad sites were connected to the DFW Midstream system.While there has been substantial development of the broader 24-county Barnett Shale over the past decade, southeastern Tarrant County,which is located in the core area of the Barnett Shale, has been largely undeveloped due to the urban landscape and the absence of naturalgas gathering infrastructure. The DFW Midstream system has addressed the historical lack of gathering infrastructure and currently providesproducers in the area with a safe, efficient and reliable solution to deliver their natural gas to market. Tarrant County, which is currently thelargest natural gas producing county in Texas, experienced an increase in natural gas production from 1.6 Bcf/d in October 2009 to 2.3 Bcf/din October 2012. Over this same period, throughput on the DFW Midstream system increased to approximately 400 MMcf/d, whichaccounted for approximately 60% of Tarrant County's increased natural gas production.We believe the production profile of wells drilled within our areas of mutual interest and flowing on the DFW Midstream system will continueto attract drilling activity over the long term as producers become more selective in their drilling locations and focus on the core areas ofcertain basins to maximize their returns. We also believe that the acreage dedicated to the DFW Midstream system has substantialremaining development as evidenced by our 100,000 acre gathering footprint and our customers' efforts to reduce well spacing below 50acres, thus maximizing recoverable reserves. We believe our strategic location in the Barnett Shale provides us with a competitive advantageto add incremental throughput with limited additional investment capital due to the anticipated future, high-density, infill drilling from ourcustomers on connected pad sites and nearby pad sites that have yet to be connected. This high-density, infill drilling is magnified in our areagiven the urban landscape and the efforts of our producer customers to minimize their surface footprint.Our SponsorsOur 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 $7.5 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, 2012,Energy Capital Partners and its affiliated12Table of Contentsfunds had 24 investment platforms with investments in the power generation, electric transmission, midstream natural gas and renewablesectors 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, 2012, GEEnergy Financial Services had invested over $20 billion in energy investments worldwide, of which approximately $2.4 billion has beencommitted to midstream-related portfolio companies.In October 2012, Summit Investments, which owns and controls our general partner, acquired a natural gas gathering and processingsystem that gathers and processes production from the Piceance and Uinta basins in Colorado and Utah for $207.0 million. In February2013, Summit Investments acquired a midstream energy company that owns, operates and is developing various natural gas gathering andprocessing assets along with crude oil and water gathering assets in the Bakken and DJ Niobrara shale plays for $513.0 million. SummitInvestments' purchase of these midstream assets was funded via a cash contribution from Energy Capital Partners. While these assetshave not been contributed to SMLP and Summit Investments is not obligated to sell these assets to SMLP, we believe they may represent afuture opportunity for execution of our business strategy.CompetitionThe natural gas midstream business is competitive. Our competitors include other midstream companies, producers and intrastate andinterstate 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 ofmutual interest and on attracting third-party volumes to our gathering systems. Additionally, we could face incremental competition to theextent we make acquisitions from third parties.Regulation of the Oil and Natural Gas IndustriesGeneral. Sales by producers of natural gas, crude oil, condensate, and NGLs are currently made at market prices. However, gathering andtransportation services are subject to various types of regulation, which may affect certain aspects of our business and the market for ourservices. The Federal Energy Regulatory Commission ("FERC") regulates the transportation of natural gas in interstate commerce and theinterstate transportation of crude oil, petroleum products and NGLs. FERC regulation includes reviewing and accepting or approving ratesand other terms and conditions for such transportation services. FERC is also authorized to prevent and sanction market manipulation innatural 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 andcrude 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 aretransacted at market prices. In 1989, the U.S. Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining priceand non-price controls affecting wellhead sales of natural gas. FERC, which has the authority under the Natural Gas Act to regulate theprices and other terms and conditions of the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for allgas resellers subject to its regulation, except interstate pipelines, to resell natural gas at market prices. Either Congress or FERC (withrespect 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 toour 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 facilitiesthat are exempt from the jurisdiction of FERC under the Natural Gas Act and the Natural Gas Policy Act of 1978 (the "NGPA"), although weare subject to FERC's anti-market manipulation regulations and certain FERC reporting requirements. The distinction between federallyunregulated gathering facilities and FERC-regulated transmission pipelines has been the subject of extensive litigation and changes in thepolicies and interpretations of laws and regulations. In addition, the status of any individual gathering system may be determined by FERCon a case-by-case basis, although FERC has made no determinations as to the status of13Table of Contentsour facilities. Consequently, the classification and regulation of gathering systems (including some of our pipelines) could change based onfuture 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. Stateregulatory authorities also have jurisdiction over the rates and practices of intrastate pipelines and gathering systems, including requirementsfor ratable takes or non-discriminatory access to pipeline services. The basis for state regulation and the degree of regulatory oversight ofgathering systems and intrastate pipelines varies from state to state. In Texas, we are regulated as a gas utility and have filed tariffs with theRailroad Commission of Texas to establish rates and terms of service for our DFW Midstream system assets. We have not been required tofile a tariff in Colorado for our Grand River system assets. Both of these states have adopted complaint-based regulation that allows naturalgas producers and shippers to file complaints with state regulators in an effort to resolve access issues and rate grievances, among othermatters. State authorities generally have not initiated investigations of the rates or practices of gathering systems or intrastate pipelines in theabsence of a complaint.Natural gas production, gathering and transportation, including the construction of new gathering facilities and expansion of existinggathering 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, asamended 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 NaturalGas Act, the NGPA, or their implementing regulations. In addition, the Federal Trade Commission holds statutory authority under theEnergy Independence and Security Act of 2007 to prevent market manipulation in petroleum markets, including the authority to request thata court impose fines of up to $1,000,000 per violation. These agencies have promulgated broad rules and regulations prohibiting fraud andmanipulation in oil and gas markets. The Commodity Futures Trading Commission is directed under the Commodity Exchange Act toprevent price manipulations in the commodity and futures markets, including the energy futures markets. Pursuant to statutory authority,the Commodity Futures Trading Commission has adopted anti-market manipulation regulations that prohibit fraud and price manipulation inthe commodity and futures markets. The Commodity Futures Trading Commission also has statutory authority to seek civil penalties of upto the greater of $1,000,000 per day per violation or triple the monetary gain to the violator for violations of the anti-market manipulationsections of the Commodity Exchange Act. We are also subject to various reporting requirements that are designed to facilitate transparencyand prevent market manipulation.Safety and Maintenance. We are subject to regulation by the U.S. Department of Transportation under the Natural Gas Pipeline Safety Actof 1968, as amended (the “NGPSA”) which establishes federal safety standards for the design, construction, operation and maintenance ofnatural gas pipeline facilities. In the Pipeline Safety Act of 1992, Congress expanded the U.S. Department of Transportation's regulatoryauthority to include regulated gathering lines that had previously been exempt from federal jurisdiction. The Pipeline Safety Improvement Actof 2002 and the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 established mandatory inspections for certain U.S. oiland natural gas transmission pipelines in high consequence areas. The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011reauthorizes funding for federal pipeline safety programs through 2015, increases penalties for safety violations, establishes additional safetyrequirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatoryrequirements for existing pipelines.The U.S. Department of Transportation has delegated the implementation of safety requirements to the Pipeline and Hazardous MaterialsSafety Administration (the "PHMSA"), which has adopted and enforces safety standards and procedures applicable to a limited number of ourpipelines. In addition, many states, including the states in which we operate, have adopted regulations, similar to existing U.S. Departmentof Transportation regulations for intrastate pipelines. Among the regulations applicable to us, the PHMSA requires pipeline operators todevelop integrity management programs for certain pipelines located in high consequence areas, which include high-population areas suchas the Dallas-Fort Worth greater metropolitan area where our DFW gathering system is located. While the majority of our pipelines meet theU.S. Department of Transportation definition of gathering lines and are thus exempt from the integrity management requirements of thePHMSA, we also operate a limited number of pipelines that are subject to the integrity management requirements. Those regulations requireoperators, including us, to:•perform ongoing assessments of pipeline integrity;14Table of Contents•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 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 and extend the integrity management requirements to certain gatheringlines. The PHMSA also recently published an advisory bulletin providing guidance on verification of records related to pipeline maximumallowable operating pressure. Pipelines that do not meet the PHMSA's record verification standards may be required to perform additionaltesting 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 OccupationalSafety and Health Act and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally andwithin the pipeline industry. In addition, the OSHA hazard communication standard, Environmental Protection Agency ("EPA") communityright-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes requirethat information be maintained concerning hazardous materials used or produced in our operations and that such information be provided toemployees, state and local government authorities and the public.Environmental MattersGeneral. Our operation of pipelines and other assets for the gathering, compressing and dehydration of natural gas and other products issubject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner oroperator of these assets, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulationscan 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 onour operations;•limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangeredor 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 formeroperations; and•enjoining the operations of facilities deemed to be in non-compliance with permits or permit requirements issued pursuant to orimposed 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 toclean up and restore sites where substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is notuncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by therelease of hazardous substances, hydrocarbons or other waste products into the environment.The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Thus, therecan be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual futureexpenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might beimposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of suchcompliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or futureregulations.The following is a discussion of the material environmental laws and regulations that relate to our business.15Table of ContentsHazardous Substances and Waste. Our operations are subject to environmental laws and regulations relating to the management andrelease 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 theinvestigation and remediation of affected areas where hazardous substances may have been released or disposed. Furthermore, the ToxicSubstances Control Act, and analogous state laws, impose requirements on the use, storage and disposal of various chemicals andchemical substances at our facilities. The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA") andcomparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons thatcontributed to the release of a hazardous substance into the environment. We may handle hazardous substances within the meaning ofCERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable underCERCLA 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 comparablestate statutes. While the Resource Conservation and Recovery Act regulates both solid and hazardous wastes, it imposes strict requirementson the generation, storage, treatment, transportation and disposal of hazardous wastes. We generate minimal hazardous waste; however, itis possible that non-hazardous wastes, which could include wastes currently generated during our operations, will in the future be designatedas hazardous wastes and, therefore, be subject to more rigorous and costly disposal requirements. Moreover, from time to time, the EPA andstate 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 previous operators haveutilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have beendisposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons andwastes have been transported for treatment or disposal. These properties and the wastes disposed thereon may be subject to CERCLA, theResource Conservation and Recovery Act and analogous state laws. Under these laws, we could be required to remove or remediatepreviously 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 anyfacts, 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 amendedseveral times since their original adoption, require the preparation of a Spill Prevention Control and Countermeasure (“SPCC”) plan forfacilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil and oilproducts, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigablewaters of the United States. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill preventionplan, which details how a facility's operations comply with the requirements. To be in compliance, the facility's SPCC plan must satisfy all ofthe applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacilitypiping), inspections and records, security, and training. Most importantly, the facility must fully implement the SPCC plan and trainpersonnel 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 andregulations regulate emissions of air pollutants from various industrial sources, including our compressor stations, and also impose variousmonitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction ormodification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with airpermits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Ourfailure 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 for air pollutioncontrol equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.Increased obligations of operators to reduce air emissions of nitrogen oxides and other pollutants from internal combustion engines intransmission service have been enacted by governmental authorities. For example, in August 2010, the EPA published new regulationsunder the Clean Air Act to control emissions of hazardous air pollutants from existing stationary reciprocating internal combustion engines. InMay 2012, the EPA proposed16Table of Contentsamendments to the final rule in response to several petitions for reconsideration. In January 2013, the EPA finalized the proposedamendments. The final amendments, which become effective on April 1, 2013, were published in the Federal Register on January 30,2013. The rule will require us to undertake certain expenditures and activities, likely including purchasing and installing emissions controlequipment, such as oxidation catalysts or non-selective catalytic reduction equipment, on all of our engines following prescribed maintenancepractices for engines (which are consistent with our existing practices), and implementing additional emissions testing and monitoring.Compliance with the final rule currently is required by October 2013. We are continuing our evaluation of the cost impacts of the final ruleand proposed amendments.In June 2011, the EPA issued a final rule modifying existing regulations under the Clean Air Act that established new source performancestandards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The final rulebecame effective in August 2011 and may require us to undertake significant expenditures, including expenditures for purchasing, installing,monitoring and maintaining emissions control equipment. In January 2013, the EPA proposed minor amendments to the final rule. We arecurrently evaluating the impact that this final rule and proposed amendments will have on our operations.In April 2012, the EPA finalized rules that establish new air emission control requirements for oil and natural gas production and natural gasprocessing operations. Specifically, the EPA's rule package includes New Source Performance Standards ("NSPS") to address emissions ofsulfur dioxide and volatile organic compounds ("VOCs"), and a separate set of emission standards to address hazardous air pollutantsfrequently associated with oil and natural gas production and processing activities. The rules establish specific new requirements regardingemissions from compressors and controllers at natural gas processing plants, dehydrators, storage tanks and other production equipment. Inaddition, the rules establish new leak detection requirements for natural gas processing plants at 500 ppm. These rules will require a numberof modifications to our operations, including the installation of new equipment to control emissions from our compressors at initial startup, or60 days after the final rule is published in the Federal Register. Compliance with such rules could result in significant costs, includingincreased capital expenditures and operating costs. In addition, the EPA rules include NSPS for completions of hydraulically fractured naturalgas wells, which may impact our customers. Before January 2015, these standards require owners/operators to reduce VOC emissionsfrom natural gas not sent to the gathering line during well completion either by flaring using a completion combustion device or by capturingthe gas using green completions with a completion combustion device, thereby capturing gas that would otherwise be flared. BeginningJanuary 2015, operators must capture the gas and make it available for use or sale, which can be done through the use of greencompletions. The standards are applicable to newly fractured wells as well as existing wells that are refractured. These requirements mayresult in increased operating costs for producers who drill near our pipelines, which could reduce the volumes of natural gas available tomove through our gathering systems.Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws imposerestrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the United States and imposerequirements affecting our ability to conduct construction activities in waters and wetlands. Certain state regulations and the general permitsissued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. Spillprevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to helpprevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act andanalogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types offacilities. We have discharge permits in place for a number of our facilities. These permits may require us to monitor and sample the stormwater runoff from such facilities. Some states also maintain groundwater protection programs that require permits for discharges oroperations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminalpenalties 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 programauthorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanicalintegrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Wedo not conduct any hydraulic fracturing activities. However, a portion of our customers' natural gas production is developed fromunconventional 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 torepeal the exemption for hydraulic fracturing from the definition of underground injection and require federal permitting and regulatory controlof hydraulic fracturing, as well as legislative proposals17Table of Contentsto 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 fracturingoperations to regulation under the Act's Underground Injection Control Program to require disclosure of chemicals used in the hydraulicfracturing process. Scrutiny of hydraulic fracturing activities continues in other ways. The federal government is currently undertaking severalstudies of hydraulic fracturing's potential impacts. The EPA release a progress report on its study in December 2012 and stated that a draftreport of the findings of the study is expected in late 2014. In addition, in October 2011, the EPA announced its intention to proposeregulations by 2014 under the Clean Water Act to regulate wastewater discharges from hydraulic fracturing and other natural gas productionactivities. 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 LandManagement after fracturing operations have been completed and includes provisions addressing well-bore integrity and flowback watermanagement plans. The Department of the Interior announced on January 18, 2013 that the Bureau of Land Management will issue arevised draft rule by March 31, 2013. 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 ofour operations.Several states, including including Texas and Colorado, have also proposed or adopted legislative or regulatory restrictions on hydraulicfracturing through additional permit requirements, public disclosure of fracturing fluid contents, operational restrictions, and temporary orpermanent 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 rulesalso include NSPS for completions of hydraulically fractured gas wells. These standards include the reduced emission completiontechniques developed in the EPA's Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standardswould be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations underthe National Emission Standards for Hazardous Air Pollutants program include maximum achievable control technology standards for thoseglycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to maximum achievable controltechnology standards. At this point, the effect these proposed rules could have on our business has not been determined. While these ruleshave been finalized, many of the rules' provisions will be phased-in over time, with the more stringent requirements like reduced emissioncompletion not becoming effective until 2015.Endangered Species Act. The Endangered Species Act restricts activities that may affect endangered or threatened species or theirhabitats. 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 policyand goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals withinfederal 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 categoricalexclusions which results in a shorter NEPA review process. The Council on Environmental Quality has announced an intention toreinvigorate NEPA reviews and in March 2012, issued final guidance that may result in longer review processes.Climate Change. Recent scientific studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases andincluding carbon dioxide and methane, may be contributing to warming of Earth's atmosphere. In response to the scientific studies,international negotiations to address climate change have occurred. The United Nations Framework Convention on Climate Change, alsoknown as the Kyoto Protocol, became effective in February 2005 as a result of these negotiations, but the United States did not ratify theKyoto Protocol. At the end of 2009, an international conference to develop a successor to the Kyoto Protocol issued a document known as theCopenhagen Accord. Pursuant to the Copenhagen Accord, the United States submitted a greenhouse gas emission reduction target of 17percent by 2020, compared with 2005 levels. We continue to monitor the international efforts to address climate change. Their effect on ouroperations cannot be determined with any certainty at this time.In the United States, legislative and regulatory initiatives are underway to limit greenhouse gas emissions. The U.S. Congress hasconsidered legislation that would control greenhouse gas emissions through a cap and trade program18Table of Contentsand several states have already implemented programs to reduce greenhouse gas emissions. The U.S. Supreme Court determined thatgreenhouse gas emissions fall within the Clean Air Act definition of an air pollutant, and in response the EPA promulgated an endangermentfinding paving the way for regulation of greenhouse gas emissions under the Clean Air Act. In 2010, the EPA issued a final rule, known asthe Tailoring Rule, that makes certain large stationary sources and modification projects subject to permitting requirements for greenhousegas emissions under the Clean Air Act.In addition, in September 2009, the EPA issued a final rule requiring the reporting of greenhouse gases from specified large greenhouse gasemission sources in the United States beginning in 2011 for emissions in 2010. In November 2010, the EPA published a final ruleexpanding 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 certain of our assets. The EPA continues to consider additional climate change requirements,such as the March 2011 proposed rules regarding future coal-fired power plants. Because regulation of greenhouse gas emissions isrelatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how thesegreenhouse gas initiatives will impact us.Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making ourproducts more or less desirable than competing sources of energy. To the extent that our products are competing with higher greenhouse gasemitting energy sources, our products would become more desirable in the market with more stringent limitations on greenhouse gasemissions. Conversely, to the extent that our products are competing with lower greenhouse gas emitting energy sources such as solar andwind, our products would become less desirable in the market with more stringent limitations on greenhouse gas emissions.EmployeesSMLP does not have any employees. All of the employees required to conduct and support its operations are employed by SummitInvestments or its affiliates. The officers of our general partner manage our operations and activities. As of December 31, 2012, SummitInvestments employed 136 people who provide direct, full-time support to our operations. None of our employees is a member of any laborunion, and we have never experienced any business interruption as a result of any labor disputes.Availability of ReportsSMLP makes certain filings with the Securities and Exchange Commission (the "SEC"), including its annual report on Form 10-K, quarterlyreports on Form 10-Q, current reports on Form 8-K and all amendments and exhibits to those reports, available free of charge through itswebsite, www.summitmidstream.com, as soon as reasonably practicable after the date they are filed with, or furnished to, the SEC. Thefilings are also available at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330.These filings are also available on the internet at www.sec.gov. SMLP’s press releases and recent investor presentations are also availableon SMLP’s website.Item 1A. Risk Factors.Limited partner units are inherently different from capital stock of a corporation, although many of the business risks to which we aresubject are similar to those that would be faced by a corporation engaged in similar businesses. The following risk factors should beconsidered together with all of the other information included in this report.If any of the following risks were to materialize, our business, financial condition or results of operations could be materiallyadversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the tradingprice of our common units could decline and an investor could lose all or part of its investment in us.Risks Related to our BusinessWe may not have sufficient cash from operations following the establishment of cash reserves and payment of fees andexpenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution or anydistribution 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 availablecash of approximately $20.0 million per quarter, or $79.9 million per year. We may not have19Table of Contentssufficient available cash from operating surplus each quarter to pay the minimum quarterly distribution. The amount of cash we candistribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter toquarter 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, natural gas and NGLs;•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;•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, natural gas, the fees we can charge, how we contract for services, ourexisting 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 ourcontrol, 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 servicesprovided 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 materialnonpayment or nonperformance by, or the curtailment of production by, any one or more of these customers could materiallyadversely 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 productionin our areas of operation it could reduce throughput on our system and, therefore, materially adversely affect our revenues, cash flow andability 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, bedisproportionately affected as compared to larger, better-capitalized companies. Any material nonpayment or nonperformance by any of ourkey customers could have a material adverse effect on our revenue and cash flows and our ability to make cash distributions to ourunitholders. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantiallydependent on a relatively small number of customers for a substantial portion of our revenue. In addition, if any one or more of our gasgathering agreements that account for 25% or more of our revenues are terminated, and such termination is reasonably expected to have aMaterial Adverse Effect (as defined in our amended and restated revolving credit facility), and a replacement agreement is not obtained within30 days, this would constitute an event of default under our amended and restated revolving credit facility and our lenders would be able toaccelerate payment of the debt outstanding thereunder.20Table of ContentsWe gather natural gas from the Piceance Basin and the Barnett Shale. Due to our lack of industry and geographicdiversification, adverse developments in our existing areas of operation could materially adversely impact our financialcondition, 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. Our assets are located exclusively in the Piceance Basin inwestern Colorado and the Barnett Shale region in north-central Texas and we intend to focus our future capital expenditures largely ondeveloping our business in these areas. As a result, our financial condition, results of operations and cash flows depend upon the demand forour services in these regions. Due to our lack of industrial and geographic diversity, adverse developments in our current segment of themidstream industry or our existing areas of operation could have a significantly greater impact on our financial condition, results of operationsand cash flows than if our operations were more diversified. For example, the natural gas we gather in the Barnett Shale is dry gas. Due torecent declines in natural gas prices, several of our customers have announced their intent to reduce capital expenditures for dry gas drillingactivities.Our operations in the Barnett Shale region could expose us to disproportionate operational and regulatory risk in that area. The location of theBarnett Shale in the Dallas-Fort Worth, Texas metropolitan area poses unique challenges associated with drilling for and gathering naturalgas 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 sitesthat can be used for infill drilling programs, which has led producers to pursue a high-density pad site drilling strategy. Furthermore, theprocess of obtaining permits for constructing additional gathering lines to deliver our customers' natural gas to market may be more timeconsuming and costly than in more rural areas. In addition, we may experience a higher rate of litigation or increased insurance and othercosts related to our operations or facilities in such highly populated areas.Significant prolonged changes in natural gas prices could affect supply and demand, reducing throughput on our systemsand 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 oursystems. Recently, the price of natural gas has been at historically low levels. The lower price of natural gas is due in part to increasedproduction, especially from unconventional sources, such as natural gas shale plays, high levels of natural gas in storage and the effects ofthe economic downturn starting in 2008. Furthermore, the amount of natural gas in storage in the continental United States has increaseddue 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 aresult of unseasonably warm winters. In response to lower natural gas prices, the number of natural gas drilling rigs has declined as anumber of producers have curtailed their exploration and production activities. We believe that over the short term, until the supply overhanghas been reduced and the economy sees more robust growth, 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 our areas ofoperation. If natural gas prices remain depressed or decrease further, it could cause sustained reductions in exploration or production activityin our areas of operation and result in a further reduction in throughput on our systems, which could have a material adverse effect on ourbusiness, financial condition, results of operations and ability to make quarterly 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 onour systems. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on our business, financialcondition, results of operations and ability to make quarterly 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 ourcustomers replacing declining production and also on our ability to maintain levels of throughput on our systems. Anydecrease 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, theproduction from which may be less than expected and will naturally decline over time. As a result, our cash flows associated with these wellswill also decline over time. To maintain or increase throughput levels on our systems, we must obtain new sources of natural gas. Theprimary factors affecting our21Table of Contentsability to obtain non-dedicated sources of natural gas include (i) the level of successful drilling activity in our areas of operation and (ii) ourability 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 oursystems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling and productiondecisions, which are affected by, among other things:•the availability and cost of capital;•prevailing and projected commodity prices, including the prices of oil, natural gas and NGLs;•demand for 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 hydraulicfracturing; 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 oil and natural gas reserves. Drilling and production activitygenerally decreases as natural gas prices decrease. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate inresponse to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factorsinclude:•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 natural gas, LNG and other commodities.Because of these factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not todevelop 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 ourunitholders.Recent declines in natural gas prices have had a negative impact on exploration, development and production activity and, if sustained, couldlead to further decreases in such activity. Sustained reductions in exploration or production activity in our areas of operation could lead tofurther reductions in the utilization of our systems, which could have a material adverse effect on our business, financial condition, results ofoperations and ability to make quarterly 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 theunconventional resource plays in which we operate generally have higher initial production rates and steeper production decline curves thanwells in more conventional basins. Should we determine that the economics of our gathering assets do not justify the capital expendituresneeded to grow or maintain volumes associated therewith, revenues associated with these assets will decline over time. In addition to capitalexpenditures to support growth, the steeper production decline curves associated with unconventional resource plays may require us to incurhigher maintenance capital expenditures over time, which will reduce our cash available for distribution from operating surplus.22Table of ContentsMany of our operating costs are fixed and do not vary with our throughput. These costs may not decline ratably or at all should we experiencea reduction in throughput, which would result in a decline in our revenue and cash flow and materially adversely affect our ability to makecash distributions to our unitholders.If our customers do not increase the volumes of natural gas they provide to our gathering systems, our growth strategy andability 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 onreceiving increased volumes from our existing customers. Other than the scheduled increases in the minimum volume commitmentsprovided for in our gas gathering agreements, our customers are not obligated to provide additional volumes to our systems, and they maydetermine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them.Reductions by our customers in our areas of mutual interest could result in reductions in throughput on our systems and materiallyadversely 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 toachieve.Our gas gathering agreements were designed to generate stable cash flows for us over the life of the minimum volume commitment contractterm while also minimizing direct commodity price risk. Under these minimum volume commitments, our customers agree to ship aminimum volume of natural gas on our gathering systems or, in some cases, to pay a minimum monetary amount, over certain periodsduring the term of the minimum volume commitment. In addition, the majority of our gas gathering agreements also include an aggregateminimum volume commitment, which is a total amount of natural gas that the customer must transport on our gathering system (or anequivalent monetary amount) over the minimum volume commitment term. If a customer's actual throughput volumes are less than itsminimum volume commitment for the applicable period, it must make a shortfall payment to us at the end of that contract month or year, asapplicable. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped for the applicableperiod and the minimum volume commitment for the applicable period, multiplied by the applicable gathering fee. To the extent that acustomer's actual throughput volumes are above or below its minimum volume commitment for the applicable period, many of our gasgathering agreements contain provisions that allow the customer to use the excess volumes or the shortfall payment to credit against futureexcess 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 andthe customer makes a shortfall payment, it may be entitled to an offset in one or more subsequent periods to the extent that itsthroughput volumes in subsequent periods exceed its minimum volume commitment for those periods. In such a situation, wewould 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 withrespect to one or more preceding months or years (as applicable). As of December 31, 2012, we recorded an aggregate of $11.8million of deferred revenue with respect to shortfall payments that could reduce gathering fees received in the next one month to nineyears to the extent that a customer's throughput volumes exceed its minimum volume commitment.•To the extent that a customer's throughput volumes exceed its minimum volume commitment in the applicable period, it may beentitled to apply the excess throughput against its aggregate minimum volume commitment, thereby reducing the period for whichits annual minimum volume commitment applies. For example, one of our DFW Midstream customers has a contracted minimumvolume commitment term from October 2010 through September 2017. However, this customer regularly shipped volumes inexcess of its minimum volume commitments and satisfied the requirements of its aggregate minimum volume commitment in thefourth quarter of 2012, thereby reducing the period for which its minimum volume commitment applies from eight years to less thanthree years. As a result of this mechanism, the weighted-average remaining period for which our minimum volume commitmentsapply 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 creditingmechanism that allows the customer to build a bank of credits that it can utilize in the future to reduce shortfall payments owed insubsequent periods, subject to expiration in the event that there is no shortfall in subsequent periods. The period over which thiscredit bank can be applied to future shortfall payments varies, depending on the particular gas gathering agreement. In such asituation, we23Table of Contentswould receive lower gathering fees in a particular contract year than we would otherwise be entitled to receive under the customer'sminimum volume commitment.Under certain circumstances, it is possible that the combined effect of the minimum volume commitment provisions could result in ourreceiving 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 35months; or•all or a substantial portion of our customers could cease shipping throughput volumes at a time when their respective aggregateminimum 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 andcash flows and our ability to make cash distributions to our unitholders.We do not intend to obtain independent evaluations of natural gas reserves connected to our gathering and transportationsystems on a regular or ongoing basis; therefore, in the future, volumes of natural gas on our systems could be less than weanticipate.We have not obtained and do not intend to obtain independent evaluations of the natural gas reserves connected to our systems on a regularor ongoing basis. Moreover, even if we did obtain independent evaluations of the natural gas reserves connected to our systems, suchevaluations may prove to be incorrect. Oil and natural gas reserve engineering requires subjective estimates of underground accumulationsof oil and natural gas and assumptions concerning future oil and natural gas prices, future production levels and operating and developmentcosts.Accordingly, we may not have accurate estimates of total reserves dedicated to some or all of our systems or the anticipated life of suchreserves. If the total reserves or estimated life of the reserves connected to our gathering and transportation systems are less than weanticipate and we are unable to secure additional sources of natural gas, it could have a material adverse effect on our business, results ofoperations, 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 andoperating results.We compete with other midstream companies in our areas of operation. Some of our competitors are large companies that have greaterfinancial, managerial and other resources than we do. In addition, some of our competitors have assets in closer proximity to gas suppliesand have available idle capacity in existing assets that would not require new capital investments for use. Our competitors may expand orconstruct gathering systems that would create additional competition for the services we provide to our customers. Because our customers donot have leases that cover the entirety of our areas of mutual interest, non-customer producers that lease acreage within any of our areas ofmutual 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 replaceexisting contracts with our customers at rates sufficient to maintain current revenue and cash flow could be materially adversely affected bythe 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 tonegotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. Wemay be unable to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure ofa particular contract with an existing customer or the overall mix of our contract portfolio. Moreover, we may be unable to obtain areas ofmutual interest from new customers in the future, and we may be unable to renew existing areas of mutual interest with current customersas 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;24Table of Contents•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 mixover time, our revenues and cash flows could decline and our ability to make cash distributions to our unitholders could be materiallyadversely affected.We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties, and anymaterial nonpayment or nonperformance by one or more of these parties could materially adversely affect our financial andoperating results.Although we attempt to assess the creditworthiness of our customers, suppliers and contract counterparties, there can be no assurance thatour assessments will be accurate or that there will not be a rapid or unanticipated deterioration in their creditworthiness, which may have anadverse impact on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. Inaddition, 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, ourfinancial 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 andregulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings withsuch parties. In addition, volatility in commodity prices might have an impact on many of our counterparties, which, in turn, could have anegative 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 theaffected operations, reduce our operations or seek out alternative service providers. There can be no assurance that any such efforts would besuccessful or would provide similar financial and operational results.If third-party pipelines or other midstream facilities interconnected to our gathering systems become partially or fullyunavailable, our revenue and cash flow and our ability to make cash distributions to our unitholders could be materiallyadversely affected.Our natural gas gathering pipelines connect to other pipelines and midstream facilities, such as processing plants, owned and operated byunaffiliated third parties. The continuing operation of such third-party pipelines and other midstream facilities is not within our control. Thesepipelines 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 fromother operational hazards. In addition, we do not have interconnect agreements with all of these pipelines and other facilities and theagreements we do have may be terminated in certain circumstances and on short notice. If any of these pipelines or other midstreamfacilities become unavailable for any reason, or, if these third parties are otherwise unwilling to receive or transport the natural gas that wegather, 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. There could be unknown events or conditions or increasedmaintenance or repair expenses and downtime associated with our pipelines that could have a material adverse effect on ourbusiness and operating results.We purchased the substantial majority of our assets in September 2009 and in October 2011. As a result, our executive management teamhas a limited history of operating our assets. There may be historical occurrences or latent issues regarding our pipeline systems that ourexecutive management team may be unaware of and that may have a material adverse effect on our business and results of operations. Thesteeper production decline curves associated with unconventional resource plays may require us to incur higher maintenance capitalexpenditures over time to connect additional wells and maintain throughput volume. Any significant increase in maintenance and25Table of Contentsrepair expenditures or loss of revenue due to the condition of our pipeline systems could materially adversely affect our business and resultsof operations and our ability to make cash distributions to our unitholders.A shortage of skilled labor in the midstream natural gas industry could reduce employee productivity and increase costs, whichcould 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, amongothers. We have from time to time encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in thefuture, our labor and overall productivity or costs could be materially adversely affected. If our labor prices increase or if we experiencematerially increased health and benefit costs with respect to our general partner's employees, our business and results of operations and ourability to make cash distributions to our unitholders could be materially adversely affected.Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If asignificant accident or event occurs for which we are not adequately insured or if we fail to recover all anticipated insuranceproceeds for significant accidents or events for which we are insured, our operations and financial results could be materiallyadversely 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 naturaldisasters 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 andequipment and pollution or other environmental damage. The location of certain of our systems in or near populated areas, includingresidential 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 aboveaffecting the areas in which we and our customers operate could have a material adverse effect on our operations. Accidents or otheroperating risks could further result in loss of service available to our customers. Such circumstances, including those arising frommaintenance and repair activities, could result in service interruptions on segments of our systems. Potential customer impacts arising fromservice interruptions on segments of our systems could include limitations on our ability to satisfy customer requirements, obligations totemporarily waive minimum volume commitments to customers during times of constrained capacity, and solicitation of existing customersby others for potential new projects that would compete directly with existing services. Such circumstances could materially adversely impactour ability to meet contractual obligations and retain customers, with a resulting negative impact on our business and results of operationsand 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 incomeand certain environmental hazards, we may not be insured against all causes of loss, claims or damage that may occur. If a significantaccident or event occurs for which we are not fully insured, it could 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 marketconditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurancecould become unavailable or available only for reduced amounts of coverage. Additionally, with regard to the assets we have acquired, wehave limited indemnification rights to recover for potential environmental liabilities.26Table of ContentsWe intend to grow our business in part by seeking strategic acquisition opportunities. If we are unable to make acquisitions oneconomically acceptable terms from Summit Investments or third parties, our future growth will be affected, and the acquisitionswe 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 byindustry participants. A material decrease in such divestitures would limit our opportunities for future acquisitions and could materiallyadversely affect our ability to grow our operations and increase our cash distributions to our unitholders.If we are unable to make accretive acquisitions from Summit Investments or third parties, whether because we are (i) unable to identifyattractive acquisition candidates or negotiate acceptable purchase contracts; (ii) unable to obtain financing for these acquisitions oneconomically acceptable terms; (iii) outbid by competitors; or (iv) we are unable to obtain necessary governmental or third-party consents orfor any other reason, then our future growth and ability to increase cash distributions will be limited. Furthermore, even if we do makeacquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operationson a per-unit basis.Any acquisition 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 maynot 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; and•customer or key employee losses at the acquired businesses.If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will nothave the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application ofthese funds and other resources.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. The construction of additions or modifications to ourexisting systems and the construction of new midstream assets involve numerous regulatory, environmental, political, legal and economicuncertainties that are beyond our control. Such expansion projects may also require the expenditure of significant amounts of capital, andfinancing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed onschedule, at the budgeted cost, or at all. Moreover, our revenue may not increase immediately upon the expenditure of funds on a particularproject.For instance, as we develop our medium pressure system to serve the Mancos and Niobrara shale formations, the construction will occurover an extended period of time, yet we will not receive any material increases in revenue until the project is completed and placed intoservice. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does notmaterialize or only materializes over a period materially longer than expected. To the extent we rely on estimates of future production in ourdecision to construct additions to our systems, such estimates may prove to be inaccurate as a result of the numerous uncertainties inherentin estimating quantities of future production. As a result, new facilities may not attract enough throughput to27Table of Contentsachieve our expected investment return, which could materially adversely affect our results of operations and financial condition.In addition, the construction of additions to our existing gathering assets may require us to obtain new rights-of-way or federal and stateenvironmental or other authorizations. The approval process for gathering activities has become increasingly challenging, due in part to stateand local concerns related to unregulated exploration and production and gathering activities in new production areas. Such authorization maynot be granted or, if granted, such authorization may include burdensome or expensive conditions. As a result, we may be unable to obtainsuch rights-of-way or other authorizations and may, therefore, be unable to connect new natural gas volumes to our systems or capitalize onother attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or authorizations or torenew 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 potentialfuture capital requirements under certain of our gas gathering agreements. Tightened capital markets could impair our ability togrow 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 alsofrequently consider and enter into discussions with third parties regarding potential acquisitions. In addition, the terms of certain of our gasgathering agreements also require us to spend significant amounts of capital, including over a short period of time, to construct and developadditional midstream assets to support our customers' development projects. For example, in connection with our acquisition of the GrandRiver system, we agreed to invest capital, subject to a maximum of $200.0 million in any annual period, to construct the necessary facilitiesto support our primary customer’s drilling program in the Mancos and Niobrara shale formations. Depending on our customers' futuredevelopment plans, it is possible that the capital we would be required to spend to construct and develop such assets could exceed our abilityto finance those expenditures using our cash reserves or available capacity under our amended and restated credit facility.We will be required to use cash from operations, incur borrowings, and/or sell additional common units or other securities to fund our futureexpansion capital expenditures. Using cash from operations to fund expansion capital expenditures will directly reduce our cash available fordistribution to unitholders. Our ability to obtain financing or to access the capital markets for future equity or debt offerings may be limited byour financial condition at the time of any such financing or offering as well as covenants in our debt agreements, general economic conditionsand contingencies and uncertainties that are beyond our control. If we are unable to raise expansion capital, we may lose the opportunity tomake acquisitions or to gather natural gas production from new upstream projects developed by our customers with whom we have agreed toconstruct and develop midstream assets in the future. Even if we are successful in obtaining funds for expansion capital expendituresthrough 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 representinglimited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required tomaintain 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 unitprice, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions.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 anddebt offerings could be higher than current levels, causing our financing costs to increase. As with other yield-oriented securities, our unitprice is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors tocompare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive ornegative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have anmaterial adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to makecash distributions at our intended levels.28Table of ContentsDebt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.As of December 31, 2012, we had approximately $199.2 million of total indebtedness and approximately $350.8 million available for futureborrowings under our $550.0 million revolving credit facility. Our future level of debt could have significant consequences, including thefollowing:•our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may beimpaired 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 portionof 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 affectedby prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If ouroperating 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 equitycapital. 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 could materially adversely affect our business, financialcondition, results of operations, ability to make cash distributions to unitholders and value of our common units.Our amended and restated revolving credit facility limits our ability to, among other things:•incur or guarantee additional debt;•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 also contains covenants requiring us to maintain certain financial ratios. Our ability tomeet those financial ratios and tests can be affected by events beyond our control, and we cannot guarantee that we will meet those ratiosand tests. In addition, our credit facility contains events of default customary for credit facilities of this size and nature.The provisions of our amended and restated revolving credit facility may affect our ability to obtain future financing and pursue attractivebusiness opportunities as well as affect our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure tocomply with the provisions of our amended and restated revolving credit facility could result in a default or an event of default that couldenable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due andpayable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders couldexperience a partial or total loss of their investment.A portion of our revenues are exposed to changes in 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, fee-based gas gathering agreements under which we are paidbased on the volumes of natural gas that we gather rather than the value of the underlying natural gas. Consequently, our existingoperations and cash flows have limited direct exposure to commodity price risk. Although we intend to enter into similar fee-based contractswith new customers in the future, our efforts to obtain such contractual terms may not be successful. For example, in the future we mayenter into percent-of-29Table of Contentsproceeds contracts with our customers, which would increase our exposure to commodity price risk, as the revenues generated from thosecontracts 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 Midstreamcustomers to offset our power expense associated with our electric-drive compression and (ii) the sale of condensate volumes that we collecton 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 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 thannatural gas, that have a greater exposure to fluctuations in commodity price risk than our current operations. Future exposure to the volatilityof 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 lawsand regulations may cause our revenue to decline or our operating and maintenance expenses to increase.Various aspects of our operations are subject to extensive and frequently changing regulation as the activities of the natural gas industry oftenare reviewed by legislators and regulators. More stringent legislation or regulation or taxation of natural gas drilling activity could directlycurtail such activity or increase the cost of drilling, resulting in reduced levels of drilling activity and therefore reduced demand for ourservices. Numerous federal, state and local departments and agencies are authorized by statute to issue, and have issued, rules andregulations and interpretations binding upon participants in the natural gas industry. The agencies establish and from time to time changepriorities, which may result in additional burdens on us, such as additional reporting requirements and more frequent audits of operations,which we have recently experienced relative to the DFW Midstream system. Our operations and the markets in which we participate areaffected by these laws, regulations and interpretations and may be affected by changes to them or their implementation, which may cause usto 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' natural gas production is developed from unconventional sources, such as shales, that requirehydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressureinto the formation to stimulate 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 injectionand require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of thechemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of the U.S. Congress. Congress willlikely continue to consider legislation to amend the Safe Drinking Water Act to provide for federal regulation of hydraulic fracturing and torequire disclosure of the chemicals used in the hydraulic fracturing process. Any such legislation could make it easier for third partiesopposed 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, theDepartment of the Interior's 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 to the Bureau of Land Management the chemicals used in hydraulic fracturingoperations after fracturing operations have been completed and includes provisions addressing well-bore integrity and flowback watermanagement plans. In addition, the EPA has commenced a multi-year study of the potential environmental impacts of hydraulic fracturing,the final results of which are expected in 2014. Similarly, in October 2011, the EPA announced its intention to propose regulations by 2014under the federal Clean Water Act to develop standards for wastewater discharges from hydraulic fracturing and other natural gas productionactivities. In addition to the EPA, the White House Council on Environmental Quality is coordinating an administration-wide review ofhydraulic fracturing practices, and a committee of the U.S. House of Representatives has conducted an investigation of hydraulic fracturingpractices. The U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect theenvironment from drilling using hydraulic fracturing completion methods. Certain members of Congress have called upon:30Table of Contents•the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources;•the Securities and Exchange Commission to investigate the natural gas industry and any possible misleading of investors or thepublic regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing; and•the U.S. Energy Information Administration to provide a better understanding of that agency's estimates regarding natural-gasreserves, including reserves from shale formations, as well as uncertainties associated with those estimates.Depending on the outcome of these studies and other initiatives, federal and state legislatures and agencies may seek to further regulatehydraulic fracturing activities.Several states, including Texas and Colorado in which our customers do business, have also proposed or adopted legislative or regulatoryrestrictions on hydraulic fracturing. The chemical ingredient information for hydraulic fracturing fluid is generally available to the publicthrough online databases, and this availability may bring more public scrutiny to hydraulic fracturing operations. We cannot predict whetherany other legislation will be enacted and if so, what its provisions would be. If additional levels of regulation and permits were requiredthrough the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs andprohibitions for producers who drill near our pipelines which could reduce the volumes of natural gas available to move through our gatheringsystems, 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 rulesalso include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completiontechniques developed in the EPA's Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standardswould be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations underthe National Emission Standards for Hazardous Air Pollutants program include maximum achievable control technology standards for thoseglycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to maximum achievable controltechnology standards. At this point, the effect these proposed rules could have on our business has not been determined. While these ruleshave been finalized, many of the rules' provisions will be phased in over time, with the more stringent requirements like reduced emissioncompletion not becoming effective until 2015.Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil andnatural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to increasedoperating costs in the production of oil and natural gas, or could make it more difficult to perform hydraulic fracturing, either of which couldhave an adverse effect on our customers. The adoption of any federal, state or local laws or the implementation of regulations regardinghydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells, increased compliance costs andtime, 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, andstate and local regulation, and could be materially affected by changes in such laws and regulations, or in the way they areinterpreted 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 toFERC's regulations thereunder, which authorize FERC to impose fines of up to $1,000,000 per day per violation of the NGA or itsimplementing regulations. In addition, the Federal Trade Commission holds statutory authority under the Energy Independence and SecurityAct of 2007 to prevent market manipulation in oil markets, and has adopted broad rules and regulations prohibiting fraud and marketmanipulation. The Federal Trade Commission is also authorized to seek fines of up to $1,000,000 per violation. The Commodity FuturesTrading Commission is directed under the Commodity Exchange Act, to prevent price manipulations for the commodity and futuresmarkets, including the energy futures markets. Pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, alsoknown as the Dodd-Frank Act, and other authority, the Commodity Futures Trading Commission has adopted anti-market manipulationregulations that prohibit fraud and price manipulation in the commodity and futures markets. The Commodity Futures Trading Commissionalso has statutory authority to seek civil penalties of up to the greater of $1,000,000 per day per violation or triple the31Table of Contentsmonetary gain to the violator for each violation of the anti-market manipulation sections of the Commodity Exchange Act.The distinction between federally unregulated gathering facilities and FERC-regulated transmission pipelines has been the subject ofextensive litigation and may be determined by FERC on a case-by-case basis, although FERC has made no determinations as to the statusof our facilities. Consequently, the classification and regulation of some of our pipelines could change based on future determinations byFERC or the courts. If our gas gathering operations become subject to FERC jurisdiction, the result may materially adversely affect the rateswe are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements withour customers.We are subject to state and local regulation regarding the construction and operation of our gathering systems, as well as state ratable takestatutes and regulations. Regulation of the construction and operation of our facilities may affect our ability to expand our facilities or buildnew facilities and such regulation may cause us to incur additional operating costs or limit the quantities of gas we may gather. Ratable takestatutes and regulations generally require gatherers to take natural gas production that may be tendered for gathering without unduediscrimination. These requirements restrict our right to decide whose production we gather. Many states have adopted complaint-basedregulation of gathering activities, which allows producers and shippers to file complaints with state regulators in an effort to resolve accessissues, rate grievances, and other matters. Other state and municipal regulations do not directly apply to our business, but may nonethelessaffect the availability of natural gas for gathering, including state regulation of production rates, maximum daily production allowable from gaswells, 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, andrevenues.We are subject to stringent 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 localenvironmental laws and regulations, including laws and regulations regarding the discharge of materials into the environment or otherwiserelating to environmental protection. Examples of these laws include:•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 Superfundlaw, and analogous state laws that regulate the cleanup of hazardous substances that may be or have been released at propertiescurrently 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 fromour 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, treatmentand 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 variouschemicals 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 toconduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines andfacilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations or at locationscurrently or previously owned or operated by us. Numerous governmental authorities, such as the EPA and analogous state agencies, havethe power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costlycorrective actions or costly pollution control measures. Failure to comply with these laws, regulations and requisite permits may result in theassessment of significant administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctionslimiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain requiredpermits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit ourgrowth and revenue.32Table of ContentsThere is a risk that we may incur significant environmental costs and liabilities in connection with our operations due to historical industryoperations and waste disposal practices, our handling of hydrocarbons and other wastes and potential emissions and discharges related toour operations. Joint and several, strict liability may be incurred, without regard to fault, under certain of these environmental laws andregulations in connection with discharges or releases of hydrocarbon wastes on, under or from our properties and facilities, many of whichhave been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including theowners 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 environmentallaws and regulations or for personal injury or property damage. For example, an accidental release from one of our pipelines could subject usto substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other thirdparties 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 andcostly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations orfinancial 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 enforcessafety standards and procedures applicable to our pipelines. In addition, many states, including the states in which we operate, have adoptedregulations similar to existing U.S. Department of Transportation regulations for intrastate pipelines. Among the regulations applicable to us,the Pipeline and Hazardous Materials Safety Administration requires pipeline operators to develop integrity management programs for certainpipelines located in high consequence areas, which include high population areas such as the Dallas-Fort Worth greater metropolitan areawhere our DFW Midstream system is located. While the majority of our pipelines meet the U.S. Department of Transportation definition ofgathering lines and are thus exempt from the Pipeline and Hazardous Materials Safety Administration's integrity managementrequirements, we also operate three pipelines in the Dallas-Fort Worth area that are subject to the integrity management requirements. Theregulations 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•implement preventive and mitigating actions.Our pipelines have become subject to regulation which has increased penalties assessed against violators and may becomesubject to more stringent safety regulation.Recently enacted pipeline safety legislation, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, reauthorizes funding forfederal pipeline safety programs through 2015, increases penalties for safety violations, establishes additional safety requirements for newlyconstructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements forexisting pipelines. The Pipeline and Hazardous Materials Safety Administration has also published an advanced notice of proposedrulemaking to solicit comments on the need for changes to its safety regulations, including whether to revise the integrity managementrequirements and extend the integrity management requirements to certain gathering lines. A new interpretation of existing laws andregulations could also significantly increase our costs or materially affect our operations. For example, Pipeline and Hazardous MaterialsSafety Administration 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 datamust be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressuresthrough 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, whichwould reduce available capacity of our pipelines. While we believe that we are in compliance with existing safety laws and regulations,increased penalties for safety violations33Table of Contentsand potential regulatory changes could have a material adverse effect on our operations, operating and maintenance expenses, andrevenues. Extending the integrity management requirements to our gathering lines would impose additional obligations on us and could addmaterial costs to our operations.Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demandfor 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 dioxideand methane that may be contributing to global warming. It presently appears unlikely that comprehensive climate legislation will be passedby either house of Congress in the near future, although energy legislation and other initiatives are expected to be proposed that may berelevant to greenhouse gas emissions issues. In addition, almost half of the states, either individually or through multi-state regionalinitiatives, have begun to address greenhouse gas emissions, primarily through the planned development of emission inventories orregional 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 emissionallowances. In general, the number of allowances available for purchase is reduced each year until the overall greenhouse gas emissionreduction goal is achieved. Depending on the scope of a particular program, we could be required to purchase and surrender allowances forgreenhouse gas emissions resulting from our operations (e.g., at compressor stations). Although most of the state-level initiatives have todate been focused on large sources of greenhouse gas emissions, such as electric power plants, it is possible that our sources, such as ourgas-fired compressors, could become subject to state-level greenhouse gas-related regulation. Depending on the particular program, we maybe 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 existingClean Air Act authority. In 2009, the EPA issued required findings under the Clean Air Act concluding that emissions of greenhouse gasespresent an endangerment to human health and the environment, and issued a final rule requiring the reporting of greenhouse gasemissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. InMay 2010, the EPA issued a final rule, also known as the Tailoring Rule, that makes certain large stationary sources and modificationprojects subject to permitting requirements for greenhouse gas emissions under the Clean Air Act. In November 2010, the EPA also issued afinal rule expanding its existing greenhouse gas emissions reporting rule for petroleum and natural gas facilities. These rules require datacollection beginning in 2011 and reporting beginning in September 2012 and require that we report our greenhouse gas emissions for certainof our assets. As a result of this continued regulatory focus, future greenhouse gas regulation of the oil and gas industry remain a possibility.Although it is not possible at this time to accurately estimate how potential future laws or regulations addressing greenhouse gas emissionswould impact our business, either directly or indirectly, any future federal or state laws or implementing regulations that may be adopted toaddress greenhouse gas emissions could require us to incur increased operating costs and could materially adversely affect demand for thenatural gas we gather or otherwise handle in connection with our services. The potential increase in the costs of our operations resulting fromany legislation or regulation to restrict emissions of greenhouse gases could include new or increased costs to operate and maintain ourfacilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxesrelated to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. While we may be able toinclude 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 indemand 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 adverseimpact on our ability to hedge risks associated with our business and increase the working capital requirements to conductthese activities.Congress adopted comprehensive financial reform legislation under the Dodd-Frank Act that establishes federal oversight and regulation ofthe over-the-counter, or OTC, derivatives market and entities, such as us, that participate in that market. This legislation requires theCommodities Futures Trading Commission and the Securities and Exchange Commission to promulgate certain rules and regulations,including rules and regulations relating to the regulation of certain swaps entities, the clearing of certain swaps, the reporting andrecordkeeping of swaps, and expanded enforcement such as establishing position limits. Although the Commodities Futures TradingCommission established position limits on certain core futures and equivalent swaps contracts, including natural34Table of Contentsgas, with exceptions for certain bona fide hedging transactions, those limits were vacated by federal district court on September 28, 2012,and will not go into effect until the Commodities Futures Trading Commission prevails on appeal of this ruling, or issues and finalizesrevised rules. In December 2012, the Commodities Futures Trading Commission published final rules regarding mandatory clearing of four classes ofinterest rate swaps and two classes of credit swaps and setting compliance dates of March 11, 2013, June 10, 2013, and, for end users ofswaps, September 9, 2013. We currently receive a fuel retainage fee from certain of our customers that is paid in-kind to offset the costs weincur to operate our electric-drive compression assets in the Barnett Shale. We currently enter into forward contracts with third parties to buypower and sell natural gas in an attempt to hedge our exposure to fluctuations in the price of natural gas with respect to those volumes. Theimpact of the Dodd-Frank Act on our hedging activities is uncertain at this time. However, the new legislation and any new regulations couldsignificantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect ouravailable liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that weencounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthycounterparties. The Dodd-Frank Act may also materially affect our customers and materially and adversely affect the demand for our services.We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to ouroperations.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 ofmore 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 orterminate or if our pipelines are not properly located within the boundaries of such rights-of-way. We obtain the rights to construct and operateour pipelines on land owned by third parties and governmental agencies for a specific period of time. If we were to be unsuccessful inrenegotiated rights-of-way, we might have to relocate our facilities. Our loss of these rights, through our inability to renew right-of-waycontracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to makecash distributions to our unitholders.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 skilledmanagement personnel with midstream natural gas industry experience and competition for these persons in the midstream natural gasindustry 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, andour failure to retain or attract our senior executives and key personnel could have a material adverse effect on our ability to effectively operateour business.If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results timelyand 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 reportsand provide an annual management report on the effectiveness of our internal control over financial reporting. Effective internal controls arenecessary for us to provide reliable and timely financial reports, prevent fraud and to operate successfully as a publicly traded partnership. Weprepare our consolidated financial statements in accordance with generally accepted accounting principles, but our internal accountingcontrols may not meet all standards applicable to companies with publicly traded securities. Our efforts to develop and maintain our internalcontrols may not be successful and we may be unable to maintain effective controls over our financial processes and reporting in the future orto 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 accountingpersonnel and management resources, we can provide no assurance as to our or our independent registered public accounting firm's futureconclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404 ofthe Sarbanes-Oxley Act of 2002. Any failure to implement and maintain effective internal controls over financial reporting will subject us toregulatory35Table of Contentsscrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likelyhave a negative effect on the trading price of our common units.Although we will be required to disclose changes made in our internal control and procedures on a quarterly basis, we will not be required tomake our first annual assessment of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002until the fiscal year ending December 31, 2013. In addition, pursuant to the recently enacted Jumpstart Our Business Startups Act, alsoknown as the JOBS Act, our independent registered public accounting firm will not be required to formally attest to the effectiveness of ourinternal control over financial reporting until the later of the year following our first annual report required to be filed with the Securities andExchange Commission or the date 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 onour cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in whichwe 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 beaffected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accountingpurposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.Risks Inherent in an Investment in UsSummit Investments owns and controls our general partner, which has sole responsibility for conducting our business andmanaging our operations as well as limited duties to us and our unitholders. Summit Investments and our general partnerhave conflicts of interest with us and they may favor their own interests to the detriment of us and our unitholders.Summit Investments controls our general partner, and has authority to appoint all of the officers and directors of our general partner, some ofwhom will also be officers, directors or principals of Energy Capital Partners, one of the two entities that own Summit Investments. Althoughour 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 alsohave a duty to manage our general partner in a manner that is in the best interests of its owner, Summit Investments. Conflicts of interestwill arise between Summit Investments, its owners and our general partner, on the one hand, and us and our unitholders, on the otherhand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of Summit Investments and itsowners 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 Summit Investments or its owners to pursue a businessstrategy that favors us, and the directors and officers of Summit Investments have a fiduciary duty to make these decisions in thebest interests of the owners of Summit Investments, which may be contrary to our interests. Summit Investments may choose toshift the focus of its investment and growth to areas not served by our assets.•Summit Investments is not limited in its ability to compete with us and may offer business opportunities or sell midstream assets tothird 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 Summit Investments and itsowners, in resolving conflicts of interest.•Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner to us and ourunitholders with contractual standards governing its duties to us and our unitholders. These contractual standards limit our generalpartner's liabilities and the rights of our unitholders with respect to actions that, without the limitations, might constitute breaches offiduciary duty.•Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholderapproval.•Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnershipinterests and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to ourunitholders.•Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified asa maintenance capital expenditure, which reduces operating surplus, or an36Table of Contentsexpansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that isdistributed 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 theborrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of thesubordination 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 funddistributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distributionrights.•Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered tous 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 ownmore 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 levelsrelated to our general partner's incentive distribution rights without the approval of the conflicts committee of the board of directors ofour 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 acquireadditional assets or businesses, which could limit our ability to grow and could materially adversely affect our results ofoperations 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 makinginvestments in midstream energy businesses. Energy Capital Partners and GE Energy Financial Services may compete with us forinvestment opportunities and may own interests in entities that compete with us. Energy Capital Partners and GE Energy FinancialServices are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. For example, GEEnergy Financial Services owns an interest in another midstream publicly traded partnership. In addition, in the future, Energy CapitalPartners or GE Energy Financial Services may acquire, construct or dispose of additional midstream or other assets and may be presentedwith new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in suchbusiness opportunities. For example, in October 2012, Summit Investments acquired a natural gas gathering and processing system in thePiceance and Uinta basins in Colorado and Utah from a third party. In February 2013, Summit Investments acquired a midstream energycompany that owns, operates and is developing various natural gas gathering and processing assets along with crude oil and water gatheringassets in multiple locations outside of our current operating areas. While Summit Investments may offer us the opportunity to buy these orother additional assets, it is not under any contractual obligation to do so and we are unable to predict whether or when such opportunitiesmay arise.Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to ourgeneral partner, its officers and directors or any of its affiliates, including our Sponsors and their respective executive officers, directors andprincipals. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be anopportunity 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 toany limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires suchopportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Thismay create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatmentof us and our unitholders.37Table of ContentsThe market price of our common units may fluctuate significantly and, due to limited daily trading volumes, an investor couldlose all or part of its investment in us.There were 14,382,577 publicly traded common units at December 31, 2012. In addition, Summit Investments, which also controls ourgeneral partner, owned 10,029,850 common and 24,409,850 subordinated units. An investor may not be able to resell its common units ator above its acquisition price. Additionally, a lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in themarket 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 unitswith contractual standards governing its duties.Our partnership agreement contains provisions that eliminate fiduciary duties to which our general partner would otherwise be held by statefiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits ourgeneral partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner or otherwise, freeof any duties to us and our unitholders, other than the implied contractual covenant of good faith and fair dealing. This entitles our generalpartner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interestof, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individualcapacity 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 generalpartner;•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 theprovisions discussed above.Our partnership agreement limits the liabilities of our general partner and the rights of our unitholders with respect to actionstaken 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 toactions 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:38Table of Contents•whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our generalpartner, 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 differentstandard 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 longas 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 assigneesresulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competentjurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged infraud 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 atransaction 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 obligatedto seek such approval;(ii)approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partnerand 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 othertransactions 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 theconflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by ourcommon unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course ofaction taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the final two subclausesabove, 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 onbehalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming suchpresumption.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 haverecourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incurindebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken byour general partner to limit its liability is not a breach of our general partner's fiduciary duties, even if we could have obtained more favorableterms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incursobligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available fordistribution to our unitholders.Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and makeacquisitions.We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, includingcommercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Asa result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.In addition, because we intend to distribute all of our available cash, we may not grow as quickly as businesses that reinvest their availablecash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capitalexpenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase ourper-unit distribution level. There are no limitations in our partnership agreement or our amended and restated revolving credit facility on ourability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial39Table of Contentsborrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the availablecash that we have to distribute to our unitholders.While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, includingprovisions 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 requiringus to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during thesubordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with theconsent of our general partner and the approval of a majority of the outstanding common units (including common units held by affiliates ofour general partner) after the subordination period has ended. As of December 31, 2012, Summit Investments, which also controls ourgeneral partner, owned 10,029,850 common units and all of our 24,409,850 outstanding subordinated units.Reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cashavailable for distribution to our common unitholders. The amount and timing of such reimbursements will be determined by ourgeneral partner.Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including SummitInvestments, for expenses they incur and payments they make on our behalf. Under our partnership agreement, we will reimburse ourgeneral partner and its affiliates for certain expenses incurred on our behalf, including administrative costs, such as compensation expensefor those persons who provide services necessary to run our business. Our partnership agreement provides that our general partner willdetermine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our generalpartner 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 quarterlydistribution and the target distribution levels related to our general partner's incentive distribution rights without the approvalof the conflicts committee of our general partner's board or our unitholders. This election may result in lower distributions to ourunitholders 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 atthe highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters (and the amount of each such distributiondid not exceed adjusted operating surplus for such quarter), to reset the initial target distribution levels at higher levels based on our cashdistribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterlydistribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding thereset election (such amount is referred to as the reset minimum quarterly distribution), and the target distribution levels will be reset tocorrespondingly 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 thatnumber of common units that would have entitled it to an average aggregate quarterly cash distribution in the prior two quarters equal to theaverage of the distributions on the incentive distribution rights in the prior two quarters. Our general partner will also be issued the number ofgeneral partner units necessary to maintain its general partner interest in us that existed immediately prior to the reset election. We anticipatethat our general partner would exercise this reset right to facilitate acquisitions or internal growth projects that would not be sufficientlyaccretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise thisreset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expectsthat we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may beexperiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and maytherefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore maybe more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distributionlevels that are less certain to be achieved in the then-current business environment. As a result, a reset election may cause our commonunitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued commonunits to our general partner in connection with resetting the target distribution levels related to our general partner's incentive distributionrights.40Table of ContentsHolders 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, unitholders 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 orongoing basis to elect our general partner or its board of directors. The board of directors of our general partner will be chosen by SummitInvestments. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability toremove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because ofthe absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability ofunitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability toinfluence 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 ownsufficient units to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding limited partner units votingtogether as a single class is required to remove our general partner. As of December 31, 2012, Summit Investments, which also controls ourgeneral partner, owned 10,029,850 common units and 24,409,850 subordinated units, or 70.5% of our outstanding limited partner units.Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliatesare not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existingarrearages on our common units will be extinguished. A removal of our general partner under these circumstances would materiallyadversely 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 acourt of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful orwanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of thebusiness, so the removal of our general partner because of the unitholder's dissatisfaction with our general partner's performance inmanaging our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units tocommon 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 andpersons 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 assetswithout the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Summit Investments totransfer 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 ina position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control overthe decisions made by the board of directors and officers. This effectively permits a change of control without the vote or consent of theunitholders.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. Ifour general partner transfers the incentive distribution rights to a third party but retains its general partner interest, our general partner maynot have the same incentive to grow our business and increase quarterly distributions to unitholders over time as it would if it had retainedownership of the incentive distribution rights. For example, a transfer of the incentive distribution rights by our general partner could reducethe likelihood of Summit Investments selling or contributing additional midstream assets to us, as Summit Investments would have less ofan economic incentive to grow our business, which in turn would impact our ability to grow our asset base.41Table of ContentsWe 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 ranksenior to the common units that we may issue at any time without the approval of our unitholders. The issuance by us of additional commonunits 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 theminimum 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 fordistribution, the distributions to holders of incentive distribution rights will increase even if the per-unit distribution on common unitsremains 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.Summit Investments may sell units in the public or private markets, and such sales could have an adverse impact on thetrading price of the common units.As of December 31, 2012, Summit Investments held an aggregate of 10,029,850 common units and 24,409,850 subordinated units. All ofthe subordinated units will convert into common units at the end of the subordination period. In addition, we have agreed to provide SummitInvestments with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the priceof 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 theright, 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 heldby unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnershipagreement. As a result, an investor may be required to sell its common units at an undesirable time or price and may not receive any returnon its investment. An investor may also incur a tax liability upon a sale of its units. As of December 31, 2012, Summit Investments owned10,029,850 common units. At the end of the subordination period, assuming no acquisitions, dispositions, retirement or additionalissuances of common units (other than upon the conversion of the subordinated units), Summit Investments will own 34,439,700 commonunits, 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 contractualobligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delawarelaw, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for theobligations of a limited partnership have not been clearly established in some of the other states in which we do business. An investor couldbe 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 ourpartnership agreement or to take other actions under our partnership agreement constitute control of our business.42Table of ContentsUnitholders 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, wemay not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that fora period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at thetime of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limitedpartners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limitedpartner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined fromthe partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to thepartnership 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 unitsand 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 areU.S. individuals or entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S. federalincome 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'sunits, 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. Theredemption 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 corporategovernance requirements.We have listed our common units on the New York Stock Exchange. Because we are a publicly traded partnership, the New York StockExchange does not require us to have, and we do not intend to have, a majority of independent directors on our general partner's board ofdirectors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance ofadditional common units or other securities, including to affiliates, will not be subject to the New York Stock Exchange's shareholder approvalrules. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the New York StockExchange corporate governance requirements.We will incur increased costs as a result of being a publicly traded partnership.We have limited history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accountingand other expenses. In addition, Section 404 of the Sarbanes-Oxley of 2002 and related rules subsequently implemented by the Securitiesand Exchange Commission and the New York Stock Exchange have required changes in the corporate governance practices of publiclytraded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities moretime-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least threeindependent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures,including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with ourpublicly traded partnership reporting requirements. We also expect these new rules and regulations to make it more difficult and moreexpensive for our general partner to obtain director and officer liability insurance and to possibly result in our general partner having to acceptreduced policy limits and coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serveon its board of directors or as executive officers.Tax RisksOur 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 ourcash 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 forfederal income tax purposes. We have not requested a ruling from the IRS on this or any other tax matter affecting us.43Table of ContentsDespite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours tobe treated as a corporation for federal income tax purposes. A change in current law could cause us to be treated as a corporation for federalincome 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 corporatetax rate, which is currently a maximum of 35%, and would likely pay state and local income tax at varying rates. Distributions wouldgenerally be taxed again as corporate dividends (to the extent of 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 cashavailable for distribution would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, therewould be material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in thevalue 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 taxationas a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterlydistribution 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 cashavailable 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 budgetdeficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of stateincome, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution. Ourpartnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-leveltaxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law onus.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 bemodified by administrative, legislative or judicial interpretation at any time. For example, from time to time members of the U.S. Congresspropose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. We are unable topredict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us and may be appliedretroactively. 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 cashdistributions 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 wedistribute, a unitholder's allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxesand, in some cases, state and local income taxes, on its share of our taxable income even if the unitholder receives no cash distributionsfrom us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual taxliability 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 thecost 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 mayadopt positions that differ from the conclusions of our counsel or from the positions we take, and the IRS's positions may ultimately besustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or thepositions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel's conclusions orthe positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have an adverse impact on the market for ourcommon units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne44Table of Contentsindirectly 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 you sell your common units, you will recognize a gain or loss for federal income tax purposes equal to the difference between the amountrealized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable incomedecrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common units yousell will, in effect, become taxable income to you if you sell such common units at a price greater than your tax basis in those common units,even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized on any sale of yourcommon units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciationrecapture. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if you sell your commonunits, you 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 taxconsequences to them.Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts ("IRAs"), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federalincome tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributionsto 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 tofile federal income tax returns and pay tax on their share of our taxable income. Tax-exempt entities and non-U.S. persons, should consult atax 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 unitspurchased. 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 andamortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positionscould adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gainfrom your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to yourtax returns.We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees ofour 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 aparticular 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 ourunits 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 istransferred. 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 asimilar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposedregulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or newTreasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among ourunitholders.A unitholder whose common units are loaned to a short seller to effect a short sale of common units may be considered ashaving disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner withrespect 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 havingdisposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to thosecommon 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 bereportable by the45Table of Contentsunitholder 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 toconsult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers fromloaning their common units.We adopted certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shiftof 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 anyunrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may beviewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certainunitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequentpurchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangibleassets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between ourgeneral 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 ourunitholders. It also could affect the amount of taxable gain from our unitholders' sale of common units and could have a negative impact onthe 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 thetermination 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% ormore of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold hasbeen met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in theclosing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive twoSchedules K-1 if relief was not available, as described below) for one fiscal year and would result in a deferral of depreciation deductionsallowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxableincome for the year of termination. Our termination currently would not affect our classification as a partnership for federal income taxpurposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new taxelections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced apublicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requestspublicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will onlyhave 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, you may become subject to state and local taxes and return filing requirements injurisdictions 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, unincorporatedbusiness taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business orcontrol property now or in the future, even if the unitholders do not live in any of those jurisdictions. Our unitholders will likely be required tofile state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, ourunitholders may be subject to penalties for failure to comply with those requirements. We initially expect to conduct business in Texas andColorado. Colorado currently imposes a personal income tax on individuals. As we make acquisitions or expand our business, we maycontrol 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.46Table of ContentsItem 2. Properties.We currently have two natural gas gathering systems which provide our gathering, compression and dehydration services. They are theGrand River system located primarily in Garfield County, Colorado and the DFW Midstream system located primarily in Tarrant County,Texas. 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. Portionsof the land on which our gathering systems and other major facilities are located are owned by us in fee title, and we believe that we havesatisfactory title to these lands. The remainder of the land on which our major facilities are located are held by us pursuant to perpetualeasements between us and the underlying fee owner, or permits with governmental authorities. Our Predecessor leased or owned theselands without any material challenge known to us relating to the title to the land upon which our assets are located, and we believe that wehave satisfactory leasehold estates or fee ownership in such lands or valid permits with governmental authorities. We have no knowledge ofany 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 toany 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 governmentalentities 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 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,except as described below, we are not currently a party to any significant legal or governmental proceedings. In addition, we are not aware ofany significant legal or governmental proceedings contemplated to be brought against us, under the various environmental protectionstatutes to which we are subject.On August 21, 2012, four former DFW Midstream employees (the "Plaintiffs") who, by virtue of their Class B membership in DFWMidstream Management LLC ("DFW Management"), collectively own an aggregate 4.1% vested net profits interests in DFW MidstreamServices LLC ("DFW Midstream"), filed a claim in the Court of Chancery of the State of Delaware against Summit Investments, SummitHoldings, DFW Midstream and DFW Management (collectively, the "Defendants") seeking dissolution and wind-up of DFW Midstream andDFW Management or, in the alternative, a repurchase of the Plaintiffs' net profits interests. The Plaintiffs also seek other unspecifiedmonetary damages, including attorneys' fees and costs. The complaint alleges that the Defendants breached (i) the DFW Midstream limitedliability company agreement; (ii) compensatory arrangements with each Plaintiff; (iii) the implied covenant of good faith and fair dealing; and(iv) in the case of Summit Investments and Summit Holdings, their alleged fiduciary duties to the Plaintiffs. The complaint further allegesthat the Defendants acted fraudulently with respect to the Plaintiffs. On September 28, 2012, the Defendants filed a motion to dismiss all ofPlaintiffs’ claims in this matter. The court heard oral arguments on the motion to dismiss on December 12, 2012, and a decision on themotion is expected in the first half of 2013. The court has stayed discovery pending its resolution of Defendants’ motion to dismiss.While we are unable to predict the outcome of this litigation, we believe that the Plaintiffs' allegations are meritless. We intend to vigorouslydefend ourselves against these allegations, and we do not believe that the dispute, even if determined adversely against us, would have amaterial effect on our financial position, results of operations or cash flows.Item 4. Mine Safety Disclosures.Not applicable.47Table of ContentsPART IIItem 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases ofEquity Securities.Our limited partner common units began trading on the New York Stock Exchange commencing with our initial public offering on September28, 2012 at a price of $20.00 per common unit. Our ticker symbol is "SMLP." As of February 28, 2013, the market price for our commonunits was $22.52 per unit and there were approximately 2,500 common unitholders, including beneficial owners of common units held instreet 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 distributionpaid per commonunit High Low 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, 2013, the board of directors of our generalpartner declared a distribution of $0.41 per unit for the quarterly period ended December 31, 2012. The distribution, which totaledapproximately $20.4 million, was paid on February 14, 2013 to unitholders of record at the close of business on February 7, 2013.Our Cash Distribution Policy and Restrictions on DistributionsGeneralOur Cash Distribution Policy. Our partnership agreement requires us to distribute all of our available cash quarterly. Our policy is todistribute to our unitholders an amount of cash each quarter that is equal to or greater than the minimum quarterly distribution stated in ourpartnership agreement. Generally, our available cash is our (i) cash on hand at the end of a quarter after the payment of our expenses andthe 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 casewere we subject to federal income tax. For additional information, see Note 7 to the audited consolidated financial statements.Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy. There is no guarantee that ourunitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or anyother distribution except to the extent we have available cash as defined in our partnership agreement. Our cash distribution policy may bechanged 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. Ouramended and restated revolving credit facility contains financial tests and covenants that we must satisfy. Should we be unable tosatisfy 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 cashdistributions to our unitholders, and the establishment or increase of those cash reserves could result in a reduction in cashdistributions to you from the levels we currently anticipate pursuant to our stated distribution policy. Any determination to establishcash reserves made by our general partner in good faith will be binding on our unitholders.•Although our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including theprovisions requiring us to distribute all of our available cash, may be amended. Our partnership agreement generally may not beamended during the subordination period without the approval of our public common unitholders other than in certain limitedcircumstances where no unitholder approval is required. However, our partnership agreement can be amended with the consent ofour general partner and the approval of a majority of the outstanding common units (including common units held by SummitInvestments) after the subordination period has ended. As of February 28, 2013, Summit48Table of ContentsInvestments owned our general partner as well as approximately 41.1% of our outstanding common units and all of oursubordinated units, representing an aggregate 70.5% limited partner interest in us.•Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policyand the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnershipagreement.•Under Delaware law, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of ourassets.•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 interestpayments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our cash available for distribution tounitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extentsuch 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 toservice or repay our debt or fund expansion capital expenditures.Our Minimum Quarterly DistributionThe board of directors of our general partner has established a minimum quarterly distribution of $0.40 per unit per quarter, or $1.60 per unitper year, to be paid no later than 45 days after the end of each fiscal quarter beginning with the quarter ending December 31, 2012. Thisequates to an aggregate cash distribution of approximately $20.0 million per quarter, or approximately $79.9 million per year, based on all ofthe units outstanding as of February 28, 2013.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 amountof 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, 2013 and the number of unitequivalents represented by the 2.0% general partner interest and the aggregate distribution amounts payable on such units during the year atour 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 units14,382,577 $5,753 $23,012Common units held by Summit Investments10,029,850 4,012 16,048Subordinated units held by Summit Investments24,409,850 9,764 39,056Long-term incentive plan participant units131,558 53 2102.0% general partner interest996,320 399 1,594Total49,950,155 $19,980 $79,920The subordination period generally will end if we have earned and paid at least $1.60 on each outstanding common unit and subordinatedunit and the corresponding distribution on our general partner's 2.0% interest for each of three consecutive, non-overlapping four-quarterperiods ending on or after December 31, 2015. The subordination period will automatically terminate and all of the subordinated units willconvert into an equal number of common units if we have earned and paid at least $2.40 (150.0% of the annualized minimum quarterlydistribution) 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 suchpayments in the future except during the subordination period. To the extent we have available cash in any future quarter during thesubordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common units, we willuse this excess available cash to pay any49Table of Contentsdistribution arrearages related to prior quarters before any cash distribution is made to holders of subordinated units. Our subordinated unitswill 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 partnershipagreement. The actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generatefrom our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as describedabove. We will pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or aboutseven days prior to such distribution date. We will make the distribution on the business day immediately preceding the indicated distributiondate if the distribution date falls on a holiday or non-business day.Stock Performance TableThe following graph compares the performance of our common units since the IPO to the S&P 500 and the Alerian MLP Index 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 50most prominent energy Master Limited Partnerships, or MLPs, and is calculated using a float-adjusted, capitalization-weighted methodology.Issuer Purchases of Equity SecuritiesWe made no repurchases of our common units during the quarter ended December 31, 2012.Equity Compensation PlansThe information relating to SMLP’s equity compensation plans required by Item 5 is included in Item 12. Security Ownership of CertainBeneficial Owners and Management and Related Stockholder Matters.Item 6. Selected Financial Data.SMLP completed its IPO on October 3, 2012. For the purposes of these financial statements, SMLP's results of operations for the yearended December 31, 2012 include the Predecessor's results of operations through the date of our IPO. The Grand River system wasacquired on October 27, 2011. We have included its financial results in the financial statements of SMLP and the Predecessor since the dateof acquisition. On September 3, 2009, Summit Investments acquired a controlling interest in DFW Midstream. We refer to DFW Midstreamas our Initial Predecessor for the period prior to such date.50Table of ContentsThe selected consolidated financial data presented as of December 31, 2012, 2011, 2010 and 2009 and for the years ended December 31,2012, 2011, 2010 and for the period from September 3, 2009 to December 31, 2009 have been derived from the audited consolidatedfinancial statements of SMLP and its Predecessor.The selected financial data for the period from January 1, 2009 to September 3, 2009 have been derived from the audited financialstatements 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 and its subsidiaries. Certain accounts suchas trade accounts receivables, accounts payable, prepaid expenses and certain accrued liabilities relating to the activities of ourInitial Predecessor were recorded on the books of other Energy Future Holdings entities and estimates of those accounts havebeen included in the consolidated financial statements;(ii)include an estimate for general and administrative expenses, as Energy Future Holdings did not allocate any of the central financeand 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 thanthe 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 thatare included in the DFW Midstream system.Due to the various asset acquisitions and the associated shift in business strategies relative to those of the Predecessor and InitialPredecessor, SMLP's financial position and results of operations may not be comparable to the historical financial position and results ofoperations of the Predecessor and the Initial Predecessor.The following table presents selected balance sheet data as of the date indicated. December 31, 2012 2011 2010 2009 (In thousands)Balance Sheet Data: Cash and cash equivalents$7,895 $15,462 $9,421 $39,455Accounts receivable33,504 27,476 10,238 1,373Property, plant and equipment, net681,993 638,190 277,765 140,704Total assets1,063,511 1,030,264 340,095 215,982Total debt199,230 349,893 — —Partners' capital819,247 n/a n/a n/aMembership interestsn/a 640,818 307,370 185,066__________n/a - Not applicable51Table of ContentsThe following table presents selected statement of operations data by entity for the periods indicated. SMLP Initial Predecessor Year ended December 31, Period fromSeptember 3, 2009to December 31,2009 Period fromJanuary 1, 2009 toSeptember 3, 2009 2012 2011 2010 (In thousands, except per-unit amounts)Statement of Operations Data: Revenue: Gathering services and other fees$149,371 $91,421 $29,358 $1,714 $1,910Natural gas and condensate sales16,320 12,439 2,533 — —Amortization of favorable and unfavorablecontracts(192) (308) (215) 19 —Total revenue165,499 103,552 31,676 1,733 1,910 Costs and expenses: Operations and maintenance51,658 29,855 9,503 1,147 1,010General and administrative21,357 17,476 10,035 2,939 600Transaction costs (1)2,020 3,166 — 3,921 —Depreciation and amortization35,299 11,367 3,874 343 882Total costs and expenses110,334 61,864 23,412 8,350 2,492Other income9 12 32 18 —Interest expense(7,340) (1,029) — — (247)Affiliated interest expense(5,426) (2,025) — — —Income before income taxes42,408 38,646 8,296 (6,599) (829)Income tax expense(682) (695) (124) (7) (8)Net income$41,726 $37,951 $8,172 $(6,606) $(837)Less: net income attributable to the pre-IPOperiod24,112 Net income attributable to the post-IPO period17,614 Less: net income attributable to the generalpartner352 Net income attributable to the limitedpartners$17,262 Earnings per common unit – basic$0.35 Earnings per common unit – diluted$0.35 Earnings per subordinated unit – basic anddiluted$0.35 __________(1) In 2012, includes transaction expenses of $0.3 million related to the acquisition of Grand River Gathering and $1.7 million related to SummitInvestments' acquisition of ETC Canyon Pipeline, LLC ("Red Rock"). Red Rock was not contributed to SMLP in connection with the IPO and is notan asset of SMLP. In 2011, includes transaction expenses of $3.2 million related to the acquisition of Grand River Gathering. In 2009, includestransaction expenses of $3.9 million that were incurred in connection with the Predecessor's formation and initial assets acquisition. Theseexpenses include an aggregate of $2.2 million paid to Energy Capital Partners and $1.7 million paid to third parties for strategic, advisory,management, legal, and consulting services.52Table of ContentsThe following table presents selected other financial data by entity for the periods indicated. SMLP Initial Predecessor Year ended December 31, Period fromSeptember 3, 2009to December 31,2009 Period fromJanuary 1, 2009 toSeptember 3, 2009 2012 2011 2010 (In thousands, except for per-unit amounts)Other Financial Data: EBITDA$90,656 $53,363 $12,353 $(6,293) $300Adjusted EBITDA103,300 56,803 12,353 (6,293) 300Capital expenditures76,698 78,248 153,719 19,519 40,777Acquisition capital expenditures— 589,462 — 44,896 —Distributable cash flow88,492 50,980 11,726 (6,275) 300Distributions declared per unit (1)0.41 n/a n/a n/a n/a__________(1) Represents the distribution declared on January 25, 2013 for the quarter ended December 31, 2012n/a - Not applicableFor a detailed discussion of the data presented above, including information regarding our use of EBITDA, adjusted EBITDA and distributablecash flow as well as their reconciliations to net income and net cash flows provided by operating activities, see Item 7. Management'sDiscussion and Analysis of Financial Condition and Results of Operations. The preceding tables should also be read in conjunction with theaudited consolidated financial statements and related notes.Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.MD&A is intended to inform the reader about matters affecting the financial condition and results of operations of SMLP and its subsidiariesand its Predecessor for the three-year period ended December 31, 2012. As a result, the following discussion should be read in conjunctionwith the audited consolidated financial statements and related notes that are included herein. Among other things, those financial statementsand the related notes include more detailed information regarding the basis of presentation for the following information. This discussioncontains forward-looking statements that constitute our plans, estimates and beliefs. These forward-looking statements involve numerousrisks and uncertainties, including, but not limited to, those discussed in "Risk Factors." Actual results may differ materially from thosecontained in any forward-looking statements.OverviewWe are a growth-oriented limited partnership focused on owning and operating midstream energy infrastructure assets that are strategicallylocated in the core producing areas of unconventional resource basins, primarily shale formations, in North America. We currently providefee-based natural gas gathering and compression services in two unconventional resource basins: (i) the Piceance Basin, which includes theMesaverde formation and the Mancos and Niobrara shale formations in western Colorado; and (ii) the Fort Worth Basin, which includes theBarnett Shale formation in north-central Texas.We generate a substantial majority of our revenue under long-term, fee-based natural gas gathering agreements. Substantially all of our gasgathering agreements are underpinned by areas of mutual interest and minimum volume commitments. Our areas of mutual interest coverapproximately 330,000 acres in the aggregate, have original terms that range from six years to 24 years, and provide that any natural gasproducing wells drilled by our customers within the areas of mutual interest will be shipped on our gathering systems. The minimumvolume commitments, which totaled 2.4 Tcf at December 31, 2012 and average approximately 639 MMcf/d through 2020, are designed toensure 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. Ourminimum volume commitments have remaining terms that range53Table of Contentsfrom seven years to 15 years and, as of December 31, 2012, had a weighted average remaining life of 11.1 years, assuming minimumthroughput volumes for the remainder of the term. The fee-based nature of these agreements enhances the stability of our cash flows bylimiting our direct commodity price exposure.Our OperationsOur results are driven primarily by the volumes of natural gas that we gather and compress across our systems. During the year endedDecember 31, 2012, we generated approximately 89% of our revenue from fee-based gathering services that we provided to our customers.During the same period, we generated approximately 11% of our revenue from (i) the sale of physical natural gas that we retained from ourDFW Midstream customers to offset our power expense associated with the operation of our electric-drive compression and (ii) the sale ofcondensate volumes that we collected on our Grand River system. We also earn revenue by charging certain customers with respect to costswe incur on their behalf for carbon dioxide treating to deliver pipeline quality natural gas to third-party pipelines and costs we incur to operateelectric-drive compression on the Grand River system.We contract with producers to gather natural gas from pad sites and central receipt points connected to the Grand River and DFW Midstreamsystems. These receipt points are connected to our gathering pipelines through which we compress and dehydrate natural gas and deliver itto downstream pipelines for ultimate delivery to end users or third-party processing plants.We currently provide substantially all of our gathering and compression services under long-term, fee-based gas gathering agreements,which limit our direct commodity price exposure. Under these agreements, we are paid a fixed fee based on the volume and thermal contentof the natural gas we gather. We are party to eight long-term gas gathering agreements with producers in the Barnett Shale. In the PiceanceBasin, we are a party to three long-term gas gathering agreements with Encana and six gas gathering agreements with five other producers,three of which are long-term agreements. These agreements provide us with a revenue stream that is not subject to direct commodity pricerisk, with the exception of the natural gas that we retain in-kind to offset the power costs we incur to operate our electric-drive compressionassets on the DFW Midstream system.We also have indirect exposure to changes in commodity prices in that persistent low commodity prices may cause our customers to delaydrilling or temporarily shut in production, which would reduce the volumes of natural gas that we gather. If our customers delay drilling ortemporarily shut-in production due to persistently low commodity prices, our minimum volume commitments assure us that we will receivea certain amount of revenue from our customers.We gather gas from both dry gas and liquids-rich regions and we believe that our gathering systems are well positioned to capture additionalvolumes from increased producer activity in these regions in the future. Dry gas regions contain natural gas reserves that are primarilycomposed of methane. Liquids-rich regions include natural gas reserves that contain natural gas liquids in addition to methane.In the Piceance Basin, our Grand River system benefits from its exposure to liquids-rich gas production from the Mesaverde formation. Theattractive economics associated with the production from this formation, combined with our minimum volume commitments from majorproducers in the area, provide us with stable cash flows and visible growth in the future. In addition, certain of our customers have jointventure agreements in place that provide for the development of portions of the Piceance Basin in our areas of mutual interest utilizing third-party funds. We believe the drilling activity from these joint ventures will benefit our Grand River system. The Grand River system alsoserves the emerging Mancos and Niobrara shale formations, which we expect will become more active to the extent that natural gas pricesincrease.The DFW Midstream system benefits from its areas of mutual interest that cover the most prolific dry gas area of the Barnett Shale. Webelieve that this area offers our customers a compelling opportunity to maximize drilling economics due to the high estimated ultimaterecovery of natural gas per well and relatively low drilling costs when compared with other dry gas resource basins. While recent marketprices for natural gas have resulted in reduced drilling activity in the Barnett Shale, a significant number of wells remain in various stages ofcompletion in our areas of mutual interest and on pad sites that have already been connected to the DFW Midstream system. These wellsrepresent an opportunity to increase throughput on the DFW Midstream system at minimal incremental capital costs. In addition, because ofthe urban environment in which the DFW Midstream system is located, we expect that this area will continue to be developed by ourcustomers using a high-density pad site drilling strategy that is designed to support multiple wells from a single location. Instead ofconstructing pipelines to multiple wells, we connect to an individual pad site, some of which can accommodate up to 30 wells, and gather allof the natural gas produced at that site, thus minimizing our future capital expenditures. This pad site strategy substantially increases theefficiency of both the producers' drilling activities as well as our gathering activities and economics.54Table of ContentsTrends and OutlookOur business has been, and we expect our future business to continue to be, affected by the key trends discussed below. Our expectationsare based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, orinterpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.Natural gas supply and demand dynamics. Natural gas continues to be a critical component of energy supply and demand in the UnitedStates. Recently, the price of natural gas has been at historically low levels, with the prompt month NYMEX natural gas futures price at$3.43 per MMBtu as of December 28, 2012, compared with a high of $13.58 per MMBtu in July 2008. The lower price of natural gas is duein part to increased production, especially from unconventional sources, such as natural gas shale plays, high levels of natural gas instorage, warm winter weather and the effects of the economic downturn starting in 2008. According to the U.S. Energy InformationAdministration (the "EIA"), average annual natural gas production in the United States increased 13.9% from 55.2 Bcf/d to 62.9 Bcf/d from2008 to 2011. Over the same time period, natural gas consumption increased only 4.5% to 66.6 Bcf/d. Furthermore, the amount of naturalgas in storage in the continental United States has increased from approximately 2.8 Tcf as of August 5, 2011 to approximately 3.2 Tcf as ofAugust 3, 2012 due to the decisions of many producers to store natural gas in the expectation of higher prices in the future and theunseasonably warm winter of 2011-2012. In response to lower natural gas prices, the number of natural gas drilling rigs has declined fromapproximately 1,403 as of December 31, 2008 to approximately 392 as of December 28, 2012 according to Smith Bits, as a number ofproducers have curtailed their natural gas exploration and production activities. We believe that over the short term, until the supply overhanghas 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 andeconomic growth, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation due to thelow prices of natural gas and stricter government environmental regulations on the mining and burning of coal. For example, according to theEIA, in December 2008, 49% of the electricity in the United States was generated by coal-fired power plants and in December 2011, 39% ofthe electricity in the United States was generated by coal-fired power plants. In January 2012, the EIA projected total annual domesticconsumption of natural gas to increase from approximately 22.9 Tcf in 2009 to approximately 26.6 Tcf in 2035. Consistent with the rise inconsumption, the EIA projects that total domestic natural gas production will continue to grow through 2035 to 27.9 Tcf. We believe thatincreasing consumption of natural gas will continue to drive natural gas drilling and production over the long term throughout the UnitedStates.Growth in production from U.S. shale plays. Over the past several years, a fundamental shift in production has emerged with the growthof 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 20.6 Tcf in 2009 to 27.9 Tcf in 2035, it expects shale gas productionto grow to 13.6 Tcf in 2035, or 49% of total U.S. dry gas production. Most of this increase is due to the emergence of unconventional naturalgas 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 as compared to most conventional plays.In recent years, well-capitalized producers have leased large acreage positions in the Piceance Basin, the Barnett Shale and otherunconventional resource plays. To help fund their drilling program in many of these areas, including in the Piceance Basin and the BarnettShale, a number of producers have also entered into joint venture arrangements with large international operators, industrial manufacturersand private equity sponsors. These producers and their joint venture partners have committed significant capital to the development of thePiceance Basin, the Barnett Shale and other unconventional resource plays, which we believe will result in sustained drilling activity.As a result of the current low natural gas price environment, some natural gas producers have cut back or suspended their drilling operationsin certain dry gas regions where the economics of natural gas production are less favorable. Drilling activities focused in liquids-rich regionshave continued and, in some cases, have increased, as the high Btu content associated with liquids-rich production enhances overall drillingeconomics, even in a low natural gas price environment.Interest rate environment. The credit markets recently have experienced near-record lows in interest rates. As the overall economystrengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. This could affect ourability to access the debt capital markets to the extent we may need to in the55Table of Contentsfuture to fund our growth. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causingour financing costs to increase accordingly. Although this could limit our ability to raise funds in the debt capital markets, we expect to remaincompetitive 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 activitiesacross the United States has resulted in increased competition for personnel and equipment. This is causing increases in the prices we payfor 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 thesecosts. 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 OperationsWe manage our business and analyze our results of operations as a single business segment. Our management uses a variety of financialand operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and reviewthese measurements on a regular basis for consistency and trend analysis. These metrics include:•throughput volume;•operations and maintenance expenses;•EBITDA and adjusted EBITDA; and•distributable cash flow.Throughput VolumeThe volume of natural gas that we gather depends on the level of production from natural gas wells connected to the Grand River and DFWMidstream systems. Aggregate production volumes are impacted by the overall amount of drilling and completion activity, as production mustbe maintained or increased by new drilling or other activity, because the production rate of a natural gas well declines over time.As a result, we must continually obtain new supplies of natural gas to maintain or increase the throughput volume on our systems. Ourability 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 ofmutual interest; and•our ability to gather natural gas that has been released from commitments with our competitors.Operations and Maintenance ExpensesWe seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating andmaintaining our assets. Direct labor costs, compression costs, insurance costs, ad valorem and property taxes, repair and non-capitalizedmaintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operations andmaintenance expense. Other than utilities expense, these expenses are relatively stable and largely independent of volumes deliveredthrough 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 ofthese compressors, which depends directly on the volume of natural gas gathered. As part of our contracts with our DFW Midstream systemcustomers, 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 quality56Table of Contentsnatural gas to third-party pipelines. With respect to the Grand River system, we either (i) consume physical gas on the system to operate ourgas-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 FlowWe define EBITDA as net income, plus interest expense, income tax expense, and depreciation and amortization expense, less interestincome and income tax benefit. We define adjusted EBITDA as EBITDA plus non-cash compensation expense and adjustments related toMVC shortfall payments. We define distributable cash flow as adjusted EBITDA plus cash interest income, less cash paid for interestexpense and income taxes and maintenance capital expenditures.EBITDA, adjusted EBITDA and distributable cash flow are used as supplemental financial measures by our management and by externalusers 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 andgeneral partner;•our operating performance and return on capital as compared to those of other companies in the midstream energy sector, withoutregard 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 shortfallpayments under our gas gathering agreements or the impact of non-cash compensation expense.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 OperationsItems Affecting the Comparability of Our Financial ResultsSMLP's future results of operations may not be comparable to the historical 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 byour operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flowgenerated from our operations, borrowings under our amended and restated revolving credit facility and future issuances of equityand debt securities. Prior to the IPO, we largely relied on internally generated cash flows and capital contributions from the Sponsorsto satisfy our capital expenditure requirements.•The historical results of operations may not be comparable to our future results of operations largely due to our IPO, which wascompleted on October 3, 2012. We anticipate incurring approximately $2.5 million (annualized) of general and administrativeexpenses attributable to operating as a publicly traded partnership.Incremental public entity costs include:(i)expenses associated with annual and quarterly reporting;57Table of Contents(ii)tax return and Schedule K-1 preparation and distribution expenses;(iii)Sarbanes-Oxley compliance expenses;(iv)expenses associated with listing on the NYSE;(v)independent auditor fees;(vi)legal fees;(vii)investor relations expenses;(viii)registrar and transfer agent fees;(ix)director and officer liability insurance costs; and(x)director compensation.These incremental general and administrative expenses are not reflected in the historical consolidated financial statements prior tothe IPO.•The historical consolidated financial statements and related notes:(i)reflect a 75% ownership interest in the DFW Midstream system, which we acquired from Texas Competitive ElectricHoldings Company LLC ("TCEH"), an indirect subsidiary of Energy Future Holdings, from September 4, 2009 to June 18,2010, the date on which we purchased the remaining 25% membership interest from TCEH;(ii)include charges associated with a transition services agreement that we entered into with Energy Future Holdings in 2009.Under the terms of the transition services agreement, we paid Energy Future Holdings $32,400 in 2012, $41,400 in 2011and $137,726 in 2010; and(iii)do not include any results of operations from the acquisition of the Grand River system prior to November 2011.58Table of ContentsResults of Operations — Combined OverviewThe following table presents certain consolidated and other financial and operating data for the periods indicated. Year ended December 31, 2012 2011 2010 (In thousands)Statement of Operations Data: Revenue: Gathering services and other fees$149,371 $91,421 $29,358Natural gas and condensate sales16,320 12,439 2,533Amortization of favorable and unfavorable contracts (1)(192) (308) (215)Total revenue165,499 103,552 31,676Costs and expenses: Operations and maintenance51,658 29,855 9,503General and administrative21,357 17,476 10,035Transaction costs2,020 3,166 —Depreciation and amortization35,299 11,367 3,874Total costs and expenses110,334 61,864 23,412Other income9 12 32Interest expense(7,340) (1,029) —Affiliated interest expense(5,426) (2,025) —Income before income taxes42,408 38,646 8,296Income tax expense(682) (695) (124)Net income$41,726 $37,951 $8,172Less: net income attributable to the pre-IPO period24,112 Net income attributable to the post-IPO period17,614 Less: net income attributable to the general partner352 Net income attributable to the limited partners$17,262 Other Financial Data (2): EBITDA (3)$90,656 $53,363 $12,353Adjusted EBITDA (3)103,300 56,803 12,353Capital expenditures (4)76,698 78,248 153,719Acquisition expenditures (4)— 589,462 —Distributable cash flow88,492 50,980 11,726 Other Operating Data: Miles of pipeline (end of period)399 372 83Number of wells (end of period) (5)2,134 1,964 160Number of pad sites (end of period)443 435 33Aggregate average throughput (MMcf/d)929 431 136__________(1) The amortization of favorable and unfavorable contracts relates to gas gathering agreements that were deemed to be above or below market atthe 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) See "Non-GAAP Financial Measures" below for additional information on EBITDA, adjusted EBITDA and distributable cash flow as well as theirreconciliations to the most directly comparable GAAP financial measure.59Table of Contents(3) EBITDA and adjusted EBITDA included transaction costs of $2.0 million in 2012 and $3.2 million in 2011. In 2010, EBITDA and adjustedEBITDA included $1.8 million of settlement expenses. These unusual and non-recurring expenses were settled in cash.(4) Capital expenditures do not include acquisition capital expenditures. In 2011, we acquired the Grand River system. In the fourth quarter of2012, we began tracking maintenance capital expenditures for the purposes of calculating distributable cash flow. Prior to the fourth quarter of2012, we did not distinguish between maintenance and expansion capital expenditures. Therefore, to calculate distributable cash flow, we haveestimated the portion of these expenditures that were maintenance capital expenditures for periods prior to the fourth quarter of 2012.(5) Excludes wells connected to nine central receipt points on the Grand River system that averaged 256 MMcf/d in 2012 and 44 MMcf/d in 2011.Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011Volume. Our revenues are primarily attributable to the volume of natural gas that we gather and compress and the rates we charge for thoseservices. Throughput volumes increased 497 MMcf/d, or 115%, to an average of 929 MMcf/d in 2012 from 431 MMcf/d in 2011 primarily dueto the October 2011 acquisition of the Grand River system and the continued development of the DFW Midstream system. As of December31, 2012, there were approximately 1,822 wells connected to the Grand River system and 289 miles of pipeline. For the year endedDecember 31, 2012, aggregate throughput averaged 575 MMcf/d on the Grand River system. There were 312 wells and 64 drilling pad sitesconnected to the DFW Midstream system as of December 31, 2012, compared with 276 wells and 58 drilling pad sites as of December 31,2011. The DFW Midstream system included 110 miles of pipeline as of December 31, 2012, compared with 104 miles of pipeline atDecember 31, 2011. Average throughput volumes for the DFW Midstream system increased largely as a result of the continued build out andan increase in well connections.Revenue. Total revenues increased $61.9 million to $165.5 million in 2012, compared with $103.6 million in 2011. The 60% increase intotal revenue was largely driven by a 63% increase in gathering services and other fees, primarily as a result of the October 2011 acquisitionof the Grand River system and increased throughput volumes on the DFW Midstream system. Gathering services and other fees increased$58.0 million to $149.4 million in 2012, compared with $91.4 million in 2011. Gathering services and other fee revenue also reflects theimpact of a decrease in aggregate average throughput rates we charge our customers. The aggregate average throughput rate for year endedDecember 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 gatheringrevenue for the Grand River system was approximately $63.1 million in 2012, compared with $11.0 million in 2011. Natural gas andcondensate sales increased 31% to $16.3 million in 2012, compared with $12.4 million in 2011, largely reflecting the contribution of theGrand 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.Operations and Maintenance Expense. Operations and maintenance expense increased $21.8 million to $51.7 million in 2012,compared with $29.9 million in 2011. The 73% increase was largely a result of Grand River system expenses incurred in 2012, partiallyoffset by a decline in expenses for the DFW Midstream system. The decrease in operations and maintenance expense for the DFWMidstream 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 thecontinued development of the DFW Midstream system. Operations and maintenance expense for the Grand River system was $26.5million in 2012, compared with $3.9 million in 2011.General and Administrative Expense. General and administrative expense increased $3.9 million to $21.4 million in 2012, comparedwith $17.5 million in 2011. The 22% increase was largely driven by an increase of expenses due to the acquisition of the Grand Riversystem in October 2011. This increase primarily reflects an increase in salaries and benefits due to increased headcount, an increase ininsurance expenses primarily as a result of our growth, and an increase in professional services expenses. These increases were partiallyoffset by a decrease in non-cash unit-based compensation.Transaction Costs. Transaction costs were $2.0 million for the year ended December 31, 2012, of which $1.7 million related to SummitInvestments' acquisition of Red Rock and $0.3 million related to the acquisition of the Grand River system. Red Rock was not contributed toSMLP in connection with the IPO and is not an asset of SMLP. EBITDA and adjusted EBITDA in 2011 included $3.2 million in transactioncosts related to the acquisition of the Grand River system.60Table of ContentsDepreciation and Amortization Expense. Depreciation and amortization expense increased to $35.3 million in 2012 from $11.4 million in2011 largely due to the acquisition of the Grand River system in October 2011 and additional assets placed into service in connection with thedevelopment of the DFW Midstream system during 2011. Depreciation and amortization expense for the Grand River system was $23.1million in 2012, compared with $3.2 million in 2011.Interest Expense and Affiliated Interest Expense. Interest expense was $7.3 million in 2012, compared with $1.0 million in 2011. Theincrease was primarily as a result of the higher 2012 balances on the revolving credit facility that we obtained in May 2011. Affiliated interestexpense was $5.4 million in 2012, compared with $2.0 million in 2011, and related to the $200.0 million promissory notes that we issued tothe Sponsors in connection with the acquisition of the Grand River system in October 2011. The promissory notes were partially prepaid inMay 2012 with the remaining balance prepaid in July 2012.Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010Volume. Our revenues are primarily attributable to the volume of natural gas that we gather and compress and the rates we charge for thoseservices. Throughput volumes increased 296 MMcf/d, or 218%, from 136 MMcf/d for the year ended December 31, 2010 to 431 MMcf/d forthe year ended December 31, 2011. This increase was due to the continued development of the DFW Midstream system. There were 276wells and 58 drilling pad sites and 160 wells and 33 drilling pad sites connected to the DFW Midstream system as of December 31, 2011 and2010, respectively. The DFW Midstream system included 104 miles and 83 miles of pipeline as of December 31, 2011 and December 31,2010, respectively. Throughput volumes for the DFW Midstream system averaged 333 MMcf/d for the year ended December 31, 2011. Weacquired the Grand River system in October 2011. Throughput volumes for the Grand River system averaged 586 MMcf/d for the twomonths that the Grand River system was included in our financial results for the year ended December 31, 2011.Revenue. Total revenue increased $71.9 million, or 227%, from $31.7 million for the year ended December 31, 2010 to $103.6 million forthe year ended December 31, 2011. Gathering services and other fees increased $62.1 million, or 211%, from $29.4 million for the yearended December 31, 2010 to $91.4 million for the year ended December 31, 2011. This increase was primarily the result of increasedthroughput volumes on the DFW Midstream system, offset by a decrease of $0.04 per Mcf, or 7%, in the average throughput rates from$0.56 per Mcf for the year ended December 31, 2010 to $0.52 per Mcf for the year ended December 31, 2011. This decrease is primarily dueto the fact that the Grand River system generates a lower average gathering fee per Mcf than our DFW Midstream system. Gas gatheringrevenue for the Grand River system was $11.0 million for the two months that the Grand River system was included in our financial resultsfor the year ended December 31, 2011. Natural gas and condensate sales increased $9.9 million, or 391%, from $2.5 million for the yearended December 31, 2010 to $12.4 million for the year ended December 31, 2011. The increase in revenue attributable to natural gas andcondensate sales is primarily the result of increased sales of natural gas that we retain from our DFW Midstream customers to offset thecosts we incur to operate our electric-drive compression assets in the Barnett Shale. Revenue associated with condensate sales for the GrandRiver system was $0.6 million for the two months ended December 31, 2011.Operations and Maintenance Expense. Operations and maintenance expense increased $20.4 million, or 214%, from $9.5 million forthe year ended December 31, 2010 to $29.9 million for the year ended December 31, 2011. This increase was primarily the result ofincreased throughput volumes on the DFW Midstream system. Utility expense for our electric drive compressors increased $9.1 million, or206%, from $4.4 million for the year ended December 31, 2010 to $13.5 million for the year ended December 31, 2011 due to increasedvolumes and the associated increased power cost to operate the compression. Operations and maintenance expenses for the Grand Riversystem were $3.9 million for the two months that the Grand River system was included in our financial results for the year ended December31, 2011.General and Administrative Expense. General and administrative expense increased $7.4 million, or 74%, to $17.5 million for the yearended December 31, 2011. We recorded non-cash compensation expense of $3.4 million for the year ended December 31, 2011 relative toprofits interests held by certain members of management. We did not record non-cash compensation expense for the year ended December31, 2010. Salary and benefit expenses increased $2.0 million, or 45%, from $4.3 million for the year ended December 31, 2010 to $6.3million for the year ended December 31, 2011 due to increased headcount to support our growth. We did not have these expenses for the yearended December 31, 2010. Due diligence costs relative to potential asset acquisitions were $1.3 million in 2011 compared to insignificant duediligence costs in 2010. The increase in G&A expenses was offset by decreases in legal expenses for the year ended December 31, 2011compared to the year ended December 31, 2010. Legal expenses decreased $2.0 million in 2011 primarily as the result of decreased legalactivities relative to relationships61Table of Contentswith contractors and sub-contractors associated with the DFW Midstream system. We had $1.8 million in settlement expenses in 2010related to a dispute with a contractor at the DFW Midstream system.Transaction Costs. Transaction costs were $3.2 million for the year ended December 31, 2011. These transaction costs were primarilyrelated to the acquisition of the Grand River system. We did not have transaction costs for the year ended December 31, 2010.Depreciation and Amortization Expense. Depreciation and amortization expense increased $7.5 million, or 192%, from $3.9 million forthe year ended December 31, 2010 to $11.4 million for the year ended December 31, 2011. This increase was primarily the result of thedepreciation associated with additional assets placed into service in connection with the development of the DFW Midstream system in 2011.Depreciation and amortization expense for the Grand River system was $3.2 million for the two months that the Grand River system wasincluded in our financial results for the year ended December 31, 2011.Interest Expense and Affiliated Interest Expense. Interest expense increased $3.1 million for the year ended December 31, 2011. Thisincrease was primarily the result of entering into our revolving credit facility in May 2011 and the related amortization of deferred loan costs of$0.6 million and the increased interest expense related to the issuance of $200 million of promissory notes to our Sponsors in connectionwith the acquisition of the Grand River system. We did not have a revolving credit facility or outstanding promissory notes in 2010 and,therefore, we had no interest expense for the year ended December 31, 2010.Non-GAAP Financial MeasuresEBITDA, adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with accounting principlesgenerally accepted in the United States of America ("GAAP"). We believe that the presentation of these non-GAAP financial measuresprovides useful information to investors in assessing our financial condition and results of operations.Net income and net cash flows provided by (used in) operating activities are the GAAP financial measures most directly comparable toEBITDA, adjusted EBITDA and distributable cash flow. Our non-GAAP financial measures should not be considered as alternatives to themost directly comparable GAAP financial measure. Furthermore, each of these non-GAAP financial measures has limitations as ananalytical tool because it excludes some but not all items that affect the most directly comparable GAAP financial measure. Some of theselimitations include:•certain items excluded from EBITDA, adjusted EBITDA and distributable cash flow are significant components in understanding andassessing 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 capitalexpenditures or contractual commitments;•EBITDA, adjusted EBITDA, and distributable cash flow do not reflect changes in, or cash requirements for, our working capitalneeds;•although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to bereplaced in the future, and EBITDA, adjusted EBITDA and distributable cash flow do not reflect any cash requirements for suchreplacements; and•our computations of EBITDA, adjusted EBITDA and distributable cash flow may not be comparable to other similarly titled measuresof other companies.We compensate for the limitations of EBITDA, adjusted EBITDA and distributable cash flows as analytical tools by reviewing the comparableGAAP financial measures, understanding the differences between the financial measures and incorporating these data points into ourdecision-making process.EBITDA, adjusted EBITDA or distributable cash flow should not be considered in isolation or as a substitute for analysis of our results asreported under GAAP. Because EBITDA, adjusted EBITDA and distributable cash flow may be defined differently by other companies in ourindustry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies,thereby diminishing their utility.62Table of ContentsNet Income-Basis Non-GAAP Reconciliation. The following table presents a reconciliation of SMLP's net income to EBITDA, adjustedEBITDA and distributable cash flow for the periods indicated. Year ended December 31, 2012 2011 2010 (In thousands)Reconciliation of Net Income to EBITDA, Adjusted EBITDA andDistributable Cash Flow: Net income$41,726 $37,951 $8,172Add: Interest expense12,766 3,054 —Income tax expense682 695 124Depreciation and amortization expense35,299 11,367 3,874Amortization of favorable and unfavorable contracts192 308 215Less: Interest income9 12 32EBITDA (1)$90,656 $53,363 $12,353Add: Non-cash compensation expense1,876 3,440 —Adjustments related to MVC shortfall payments (2)10,768 — —Adjusted EBITDA (1)$103,300 $56,803 $12,353Add: Interest income9 12 32Less: Cash interest paid8,283 2,463 —Cash taxes paid650 223 10Maintenance capital expenditures (3)5,884 3,149 649Distributable cash flow$88,492 $50,980 $11,726__________(1) EBITDA and adjusted EBITDA included transaction costs of $2.0 million in 2012 and $3.2 million in 2011. In 2010, EBITDA and adjustedEBITDA included $1.8 million of settlement expenses. These unusual and non-recurring expenses were settled in cash. For additionalinformation, see "Results of Operations" above.(2) Adjustments related to MVC shortfall payments account for (i) the net increases or decreases in deferred revenue for MVC shortfall paymentsand (ii) our inclusion of expected annual MVC shortfall payments. We include or will include a proportional amount of these historical or expectedminimum volume commitment shortfall payments in each quarter prior to the quarter in which we actually receive the shortfall payment.(3) Maintenance capital expenditures are cash expenditures (including expenditures for the addition or improvement to, or the replacement of,our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-termoperating income or operating capacity. In the fourth quarter of 2012, we began tracking maintenance capital expenditures for the purposes ofcalculating distributable cash flow. Prior to the fourth quarter of 2012, we did not distinguish between maintenance and expansion capitalexpenditures. Therefore, to calculate distributable cash flow, we have estimated the portion of these expenditures that were maintenance capitalexpenditures for periods prior to the fourth quarter of 2012.63Table of ContentsCash Flow-Basis Non-GAAP Reconciliation. The following table presents a reconciliation of SMLP's net cash flows provided by operatingactivities to EBITDA, adjusted EBITDA and distributable cash flow for the periods indicated. Year ended December 31, 2012 2011 2010 (In thousands)Reconciliation of Net Cash Flows Provided by Operating Activities toEBITDA, Adjusted EBITDA and Distributable Cash Flow: Net cash provided by operating activities$89,488 $39,942 $9,553Add: Interest expense (1)5,838 469 —Income tax expense682 695 124Changes in operating assets and liabilities(3,467) 15,709 2,708Less: Non-cash compensation expense1,876 3,440 —Interest income9 12 32EBITDA (2)$90,656 $53,363 $12,353Add: Non-cash compensation expense1,876 3,440 —Adjustments related to MVC shortfall payments (3)10,768 — —Adjusted EBITDA (2)$103,300 $56,803 $12,353Add: Interest income9 12 32Less: Cash interest paid8,283 2,463 —Cash taxes paid650 223 10Maintenance capital expenditures (4)5,884 3,149 649Distributable cash flow$88,492 $50,980 $11,726__________(1) Interest expense presented in the cash flow-basis non-GAAP reconciliation above differs from the interest expense presented in the netincome-basis non-GAAP reconciliation presented earlier due to adjustments for amortization of deferred loan costs and paid in kind interest on thepromissory notes payable to our Sponsors. For the year ended December 31, 2012, interest expense excluded $1.5 million of amortization ofdeferred loan costs and $5.4 million of paid in kind interest. For the year ended December 31, 2011, interest expense presented excluded $0.6million of amortization of deferred loan costs and $2.0 million of paid in kind interest.(2) EBITDA and adjusted EBITDA included transaction costs of $2.0 million in 2012 and $3.2 million in 2011. In 2010, EBITDA and adjustedEBITDA included $1.8 million of settlement expenses. These unusual and non-recurring expenses were settled in cash. For additionalinformation, see "Results of Operations" above.(3) Adjustments related to MVC shortfall payments account for (i) the net increases or decreases in deferred revenue for MVC shortfall paymentsand (ii) our inclusion of expected annual MVC shortfall payments. We include or will include a proportional amount of these historical or expectedminimum volume commitment shortfall payments in each quarter prior to the quarter in which we actually receive the shortfall payment.(4) Maintenance capital expenditures are cash expenditures (including expenditures for the addition or improvement to, or the replacement of,our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-termoperating income or operating capacity. In the fourth quarter of 2012, we began tracking maintenance capital expenditures for the purposes ofcalculating distributable cash flow. Prior to the fourth quarter of 2012, we did not distinguish between maintenance and expansion capitalexpenditures. Therefore, to calculate distributable cash flow, we have estimated the portion of these expenditures that were maintenance capitalexpenditures for periods prior to the fourth quarter of 2012.64Table of ContentsLiquidity and Capital ResourcesPrior to our IPO, our sources of liquidity included cash generated from operations, equity investments by our Sponsors, and borrowingsunder the revolving credit facility. In October 2012, we completed an IPO of our common units. For additional information, see Note 1 to theaudited consolidated financial statements. In the periods following the IPO, we expect our sources of liquidity to include:•cash generated from operations;•borrowings under the revolving credit facility; and•additional issuances of debt and equity securities.Cash FlowsThe components of the change in cash and cash equivalents were as follows: Year ended December 31, 2012 2011 2010 (In thousands)Net cash provided by (used in) operating activities$89,488 $39,942 $9,553Net cash provided by (used in) investing activities(76,698) (667,710) (153,719)Net cash provided by (used in) financing activities(20,357) 633,809 114,132Change in cash and cash equivalents$(7,567) $6,041 $(30,034)Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Cash flows from operating activities increasedby $49.5 million in 2012 largely as result of the increase in volumes on the DFW Midstream system and the inclusion of a full year of GrandRiver system operations in 2012.Cash flows used in investing activities decreased in 2012 primarily as a result of the acquisition of the Grand River system in 2011. Capitalexpenditures on the DFW Midstream system were $40.3 million in 2012, compared with $78.2 million in 2011. Capital expenditures fornew projects on the Grand River system were $32.6 million in 2012.Cash flows from financing activities in 2012 reflect the May 2012 borrowing of $163.0 million under the revolving credit facility, of which weused $160.0 million to prepay principal amounts outstanding under certain unsecured promissory notes payable to the Sponsors. In July2012, we borrowed $50.0 million under the revolving credit facility and used $49.2 million of the proceeds to repay the balance of theunsecured promissory notes payable to the Sponsors. Cash flows provided by financing activities also reflect proceeds of $263.1 million fromthe issuance of our common units in connection with our IPO (including the proceeds from the exercise of the underwriters' option topurchase additional common units). We used $140.0 million of the IPO proceeds to pay down our revolving credit facility. We also paid $88.0million to reimburse Summit Investments for certain capital expenditures it incurred with respect to assets it contributed to us and distributed$35.1 million to Summit Investments for the common units it sold from the units originally allocated to it in connection with the exercise ofthe underwriters' option to purchase additional common units. We also made additional repayments totaling $20.8 million under therevolving credit facility in 2012. Financing cash flows in 2012 included $3.3 million of deferred loan costs.Cash flows from financing activities in 2011 include $200.0 million of proceeds from the execution of promissory notes payable to theSponsors to fund a portion of the purchase of the Grand River system. They also include $410.0 million of contributions from the Sponsorsto acquire the Grand River system and $15.0 million to support capital needs related to the construction of the DFW Midstream system.Additionally, the Predecessor made a distribution to Energy Capital Partners of $132.9 million out of the $147.0 million drawn on therevolving credit facility. The Predecessor incurred $5.2 million of deferred loan costs in 2011.Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010. Cash flows from operating activities increasedby $30.4 million, or 318%, to $40.0 million in 2011 from $9.6 million in 2010. The increase in cash flows from operating activities was adirect result of the significant increase in volumes on the DFW Midstream system during 2011, compared with 2010 and the inclusion of twomonths of operations on the Grand River system in 2011.Cash flows used for investing activities increased by $514.0 million, or 334%, to $667.7 million in 2011 from $153.7 million in 2010. Theincrease in cash flows used for investing activities was primarily due to the acquisition of the Grand River system for $589.5 million. Capitalexpenditures decreased by $75.5 million, or 49%, to $78.2 million in65Table of Contents2011 from $153.7 million in 2010. Capital expenditures in 2010 were higher due to the installation and commissioning of compressorstations on the DFW Midstream system.Cash flows from financing activities increased by $519.7 million, or 455%, to $633.8 million in 2011 from $114.1 million in 2010. Theincrease in cash flows from financing activities was primarily due to the acquisition of the Grand River system. The Predecessor receivedequity contributions of $410.0 million and a $200.0 million non-recourse loan from the Sponsors to acquire the Grand River system. ThePredecessor closed on the revolving credit facility in May 2011. Upon closing the revolving credit facility, the Predecessor made a $132.9million distribution to Energy Capital Partners from the $142.0 million drawn at closing.Contractual ObligationsThe table below summarizes our contractual obligations and other commitments as of December 31, 2012: Total Less than 1 year 1-3 years 3-5 years More than 5years (In thousands)Long-term debt and interest payments (1)$225,508 $7,691 $15,382 $202,435 $—Operating leases (2)3,155 859 1,449 847 —Total contractual obligations$228,663 $8,550 $16,831 $203,282 $—__________(1) Includes a 0.50% commitment fee on the unused portion of the revolving credit facility. See Note 6 to the audited consolidated financialstatements for additional information.(2) See Note 11 to the audited consolidated financial statements for additional information.Off-Balance Sheet ArrangementsWe had no off-balance sheet arrangements as of or during the year ended December 31, 2012.Capital RequirementsThe natural gas gathering segment of the midstream energy business is capital-intensive, requiring significant investment for themaintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and othermidstream assets and facilities. Our partnership agreement requires that we categorize our capital expenditures as either:•maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or thereplacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made tomaintain our long-term operating income or operating capacity; or•expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect willincrease our operating income or operating capacity over the long term.Total capital expenditures were as follows: Year ended December 31, 2012 2011 2010 (In thousands)Capital expenditures$76,698 $78,248 $153,719In 2012, total capital expenditures were largely the result of the construction of new pipeline and compression infrastructure to connect newpad sites on our DFW Midstream system and to install meters and build out medium-pressure infrastructure on our Grand River system. In2011, total capital expenditures were primarily associated with the construction of new pipeline infrastructure to connect new pad sites on ourDFW Midstream system. In 2010, total capital expenditures were largely attributable to the installation and commissioning of compressorstations on the DFW Midstream system.In the fourth quarter of 2012, we began tracking maintenance capital expenditures for the purposes of calculating distributable cash flow. Priorto the fourth quarter of 2012, we did not distinguish between maintenance and66Table of Contentsexpansion capital expenditures. Therefore, to calculate distributable cash flow, we have estimated the portion of these expenditures that weremaintenance capital expenditures for periods prior to the fourth quarter of 2012.We anticipate that we will continue to make significant expansion capital expenditures in the future. Consequently, our ability to develop andmaintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. We expect that our futureexpansion capital expenditures will be funded by borrowings under the revolving credit facility and the issuance of debt and equity securities.DistributionsBased on the terms of SMLP’s partnership agreement, SMLP expects that it will distribute to its unitholders most of the cash generated by itsoperations. As a result, SMLP expects to fund future capital expenditures from cash and cash equivalents on hand, non-distributed cash flowgenerated from its operations, borrowings under the revolving credit facility and future issuances of equity and debt securities. Historically,the Predecessor largely relied on internally generated cash flows and capital contributions from Energy Capital Partners and GE EnergyFinancial Services to satisfy its capital expenditure requirements.There were no cash distributions paid by SMLP prior to 2013 other than the distribution of proceeds from the IPO. On January 23, 2013, theboard of directors of our general partner declared a distribution of $0.41 per unit for the quarterly period ended December 31, 2012. Thedistribution, which totaled approximately $20.4 million, was paid on February 14, 2013 to unitholders of record at the close of business onFebruary 7, 2013.Revolving Credit FacilityEffective May 7, 2012, Summit Holdings amended and restated its revolving credit facility with a syndicate of lenders to increase itsborrowing capacity from $285.0 million to $550.0 million. Substantially all of SMLP’s assets are pledged as collateral under the revolvingcredit facility. It matures in May 2016 and, at our option, borrowings thereunder bear interest at a variable rate per annum equal to either (i)the London InterBank Offered Rate plus the applicable margins ranging from 2.5% to 3.5% or (ii) a base rate plus the applicable marginsranging from 1.5% to 2.5%.The revolving credit facility contains affirmative and negative covenants customary for credit facilities of its size and nature, that, among otherthings, limit or restrict our ability (as well as the ability of our subsidiaries) to:•permit the ratio of our trailing 12-month EBITDA to our consolidated cash interest charges as of the end of any fiscal quarter to beless than 2.50 to 1.00;•permit the ratio of our consolidated net debt to trailing 12-month EBITDA on the last day of any quarter to be above 5.00 to 1.00 (or5.50 to 1.00 if we have made certain business acquisitions);•incur any additional debt, subject to customary exceptions for certain permitted additional debt, or incur liens on assets, subject tocustomary exceptions for permitted liens;•make any investments, subject to customary exceptions for certain permitted investments;•engage in certain mergers, consolidations, sales of assets or acquisitions, subject to customary exceptions for permitted transactionsof such types;•pay dividends or make cash distributions, provided that we may make quarterly distributions to our unitholders, so long as nodefault or event of default under the amended and restated credit agreement then exists or would result therefrom, and subject tocompliance (on both a pro forma basis and after giving effect to the making of such distribution) with our financial performancecovenants under the amended and restated credit agreement;•enter into any swap agreements or power purchase agreements, subject to customary exceptions, such as the entry into swapagreements and power purchase agreements in the ordinary course of business; and•enter into leases that would cumulatively obligate payments in excess of $30.0 million over any 12-month period.As of December 31, 2012, we were in compliance with the financial and other covenants in our revolving credit facility.The revolving credit facility also contains events of default customary for credit facilities of its size and nature, including, but not limited to:•events of default resulting from our failure to comply with covenants;67Table of Contents•the occurrence of a change of control of our general partner;•the institution of insolvency or similar proceedings against us;•the occurrence of a default under any other material indebtedness we may have; and•the termination of any one or more or our gas gathering agreements accounting for 25% or more of our revenue that results in amaterial adverse effect (as defined in the amended and restated credit agreement) and for which a replacement gas gatheringagreement with substantially similar terms is not entered into within 30 days after such termination.Upon the occurrence of an event of default, subject to the terms and conditions of the revolving credit facility, the lenders may, in addition toexercising other remedies, declare any outstanding principal and any accrued and unpaid interest to be immediately due and payable. Therewere no defaults during 2012.We expect to use future borrowings under the revolving credit facility for working capital and other general partnership purposes and capitalexpenditures. For additional information, see Note 6 to the audited consolidated financial statements.Promissory Notes Payable to SponsorsIn connection with our acquisition of the Grand River system in 2011, the Predecessor executed promissory notes, on an unsecured basis,with our Sponsors. The notes totaled $200.0 million, had an 8% interest rate and a maturity date of October 2013. In July 2012, thePredecessor repaid the promissory notes in full. For additional information, see Note 12 to the audited consolidated financial statements.Credit Risk and Customer ConcentrationWe examine the creditworthiness of third-party customers to whom we extend credit and manage our exposure to credit risk through creditanalysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepaymentsor guarantees. A significant percentage of our revenue is attributable to three producer customers and one natural gas marketer. For additionalinformation, see Note 13 to the audited consolidated financial statements.Critical Accounting Policies and EstimatesWe prepare our financial statements in accordance with GAAP. These principles are established primarily by the Financial AccountingStandards Board. We employ methods, estimates and assumptions based on currently available information when recording transactionsresulting from business operations. Our significant accounting policies are described in Note 2 to the audited consolidated financialstatements.The estimates that we deem to be most critical to an understanding of our financial position and results of operations are those related todetermination of fair value and recognition of deferred revenues. The preparation and evaluation of these critical accounting estimates involvethe use of various assumptions developed from management's analyses and judgments. Subsequent experience or use of other methods,estimates or assumptions could produce significantly different results. Our critical accounting estimates are as follows:Recognition and Impairment of Long-Lived AssetsOur long-lived assets include property, plant and equipment, our contract intangible assets and goodwill.Property, Plant and Equipment and Intangible Assets. As of December 31, 2012, we had net property, plant and equipment with acarrying value of approximately $682.0 million and net intangible assets with a carrying value of approximately $285.5 million.When evidence exists that we will not be able to recover a long-lived asset's carrying value through future cash flows, we write down thecarrying value of the asset to its estimated fair value. We test assets for impairment when events or circumstances indicate that the carryingvalue of a long-lived asset may not be recoverable. With respect to property, plant and equipment and our contract intangible assets, thecarrying value of a long-lived asset is not recoverable if the carrying value exceeds the sum of the undiscounted cash flows expected to resultfrom the asset's use and eventual disposal. In this situation, we recognize an impairment loss equal to the amount by which the carryingvalue exceeds the asset's fair value. We determine fair value using an income approach in which we discount the asset's expected futurecash flows to reflect the risk associated with achieving the underlying cash68Table of Contentsflows. During the three-year period ended December 31, 2012, we concluded that none of our long-lived assets had been impaired.For additional information, see Notes 2, 4 and 5 to the audited consolidated financial statements.Goodwill. Goodwill represents consideration paid in excess of the fair value of the identifiable assets acquired in a business combination. Asof December 31, 2012, we had goodwill of $45.5 million that we recognized in connection with the acquisition of the Grand River system inOctober 2011. In the second quarter of 2012, we received the remaining information needed to determine the value associated with certainacquired assets. We then finalized the purchase price allocation and recognized the assets acquired and liabilities assumed on a retrospectivebasis. Management believes that the goodwill recorded upon the finalization of the allocation represents the incremental value of future cashflow potential attributed to estimated future gathering services within the emerging Mancos and Niobrara shale developments.We evaluate goodwill for impairment annually on September 30. We also evaluate goodwill whenever events or circumstances indicate thatit is more likely than not that the fair value of a reporting unit is less than its carrying amount.We test goodwill for impairment using a two-step quantitative test. In step one, we compare the fair value of the reporting unit to its carryingvalue, including goodwill. If the reporting unit's fair value exceeds its carrying amount, we conclude that the goodwill of the reporting unit hasnot been impaired and no further work is performed. If we determine that the reporting unit's carrying value exceeds its fair value, we proceedto step two. In step two, we compare the carrying value of the reporting unit to its implied fair value. If we determine that the carrying amountof a reporting unit's goodwill exceeds its implied fair value, we recognize the excess of the carrying value over the reporting unit's impliedvalue as an impairment loss.We performed our annual goodwill impairment analysis as of September 30, 2012 and determined that no factors existed which would leadus to conclude that an impairment of goodwill was necessary. No events or circumstances have occurred since the Grand River systemacquisition in October 2011 that would require an interim impairment test. Presently, we do not believe that the Grand River systemreporting unit is at risk of failing step one. Prior to the acquisition of the Grand River system, the Predecessor had no goodwill.For additional information, see Notes 2, 3 and 5 to the audited consolidated financial statements.Minimum Volume CommitmentsThe majority of our gas gathering agreements provide for a monthly or annual MVC from our customers. As of December 31, 2012, we hadMVCs totaling 2.4 Tcf through 2026.Under these monthly or annual MVCs, our customers agree to ship a minimum volume of natural gas on our gathering systems or to pay aminimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to us at the end ofthe contract month or year, as applicable, if its actual throughput volumes are less than its MVC for that month or year. Certain customersare entitled to utilize shortfall payments to offset gathering fees in one or more subsequent periods to the extent that such customer'sthroughput volumes in subsequent periods exceed its MVC for that period. These contract provisions range from one month to nine years.We recognize customer billings for obligations under their MVCs as deferred revenue when the customer has the right to utilize shortfallpayments to offset gathering fees in subsequent periods. As of December 31, 2012, we had current deferred revenue totaling approximately$0.9 million and noncurrent deferred revenue totaling approximately $10.9 million. We classify deferred revenue as a current liability forarrangements where the expiration of a customer's right to utilize shortfall payments is 12 months or less. We classify deferred revenue asnoncurrent for arrangements where the expiration of the right to utilize shortfall payments and our estimate of its potential utilization is morethan 12 months.We recognize revenue when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery hasoccurred or services have been rendered, (iii) the price is fixed or determinable, and (iv) collectability is reasonably assured. With respect toMVCs, we reclassify deferred revenue to gathering services and other fees revenue under these arrangements once all potential performanceobligations associated with the related MVC have either (i) been satisfied through the gathering of future excess volumes, or (ii) expired (orlapsed) through the passage of time pursuant to the terms of the natural gas gathering agreement.For additional information, see Note 2 to the audited consolidated financial statements.69Table of ContentsCompensatory AwardsCertain of our current and former employees were granted Class B membership interests, classified as net profits interests, in DFWMidstream or Summit Midstream Management, LLC. We refer to these interests collectively as the net profits interests. The net profitsinterests participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higherpriority vested net profits interests. The net profits interests are accounted for as compensatory awards. The net profits interests vest ratablyover four to five years (as defined in the underlying award agreement), and provide for accelerated vesting in certain limited circumstances,including a qualifying termination following a change in control (as defined in the underlying award agreement and the Summit MidstreamPartners LLC Agreement and the DFW Midstream Amended and Restated Limited Liability Company Agreement and ContributionAgreement). With the assistance of a third-party valuation firm, we determined the fair value of the net profits interests as of the respectivegrant dates. The net profits interests were valued utilizing an option pricing method, which models the Class A and Class B membershipinterests as call options on the underlying enterprise equity value and considers the rights and preferences of each class of equity to allocate afair value to each class. We used a combination of the income and market approaches, including the following assumptions and internal andexternal factors in determining the grant date fair value of the net profits interests: (i) assumptions underlying the enterprise value used inconnection with the option pricing method, including the discount rate applied to estimated future cash flows, forecasted gathering volumes,revenues and costs, equity performance relative to peer group members, equity market risk premium, enterprise-specific risk premium, andterminal growth rates; (ii) holding period restrictions; (iii) discounts for lack of marketability; and (iv) expected volatility rates based on thehistorical and implied volatility of other midstream services companies whose share or option prices are publicly available.For additional information, see Note 9 to the audited consolidated financial statements.Item 7A. Quantitative and Qualitative Disclosures About Market Risk.Interest Rate RiskWe have exposure to changes in interest rates on our indebtedness associated with the revolving credit facility. The credit markets haverecently experienced historical lows in interest rates. As the overall economy strengthens, it is possible that monetary policy will tightenfurther, resulting in higher interest rates to counter possible inflation. Interest rates on floating rate credit facilities and future debt offeringscould be higher than current levels, causing our financing costs to increase accordingly.A hypothetical 1.0% increase (decrease) in interest rates would have increased (decreased) our interest expense by approximately $2.4million for the year ended December 31, 2012.Commodity Price RiskBecause we currently generate a substantial majority of our revenues pursuant to long-term, fee-based gas gathering agreements thatinclude MVCs and AMIs, our only direct commodity price exposure relates to (i) our sale of physical natural gas we retain from our DFWMidstream customers, (ii) our procurement of electricity to operate our electric-drive compression assets on the DFW Midstream system and(iii) the sale of condensate volumes that we collect on the Grand River system. Our gas gathering agreements with our Barnett Shalecustomers permit us to retain a certain quantity of natural gas that we sell to offset the power costs we incur to operate our electric-drivecompression assets. Our gas gathering agreements with our Grand River customers permit us to retain condensate volumes from theGrand River system gathering lines. We manage our direct exposure to natural gas and power prices through the use of forward powerpurchase contracts with wholesale power providers that require us to purchase a fixed quantity of power at a fixed heat rate based onprevailing natural gas prices on the Waha Hub Index. Because we also sell our retainage gas at prices that are based on the Waha HubIndex, we have effectively fixed the relationship between our compression electricity expense and natural gas sales. We do not enter into riskmanagement contracts for speculative purposes.Item 8. Financial Statements and Supplementary Data.The audited consolidated financial statements required to be included in this Annual Report on Form 10-K appear immediately following thesignature page to this Form 10-K, beginning on page F-1.70Table of ContentsItem 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure Matters.There have been no changes in, or disagreements with, accountants on accounting and financial disclosure matters during the years endedDecember 31, 2012 and 2011.Item 9A. Controls and Procedures.Disclosure Controls and ProceduresSMLP’s management, with the participation of the Chief Executive Officer and Chief Financial Officer of SMLP's general partner, hasevaluated the effectiveness of SMLP’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) underthe Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of the end of the period covered by this annual report (the"Evaluation Date"). Based on such evaluation, the Chief Executive Officer and Chief Financial Officer of SMLP's general partner haveconcluded that, as of the Evaluation Date, SMLP’s disclosure controls and procedures are effective.Changes in Internal Control Over Financial ReportingThere have not been any changes in SMLP’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f)under the Exchange Act) during the fourth fiscal quarter of 2012 that have materially affected, or are reasonably likely to materially affect,SMLP's internal control over financial reporting.Management's Report on Internal Control Over Financial ReportingThis annual report does not include a report of management's assessment regarding internal control over financial reporting or an attestationreport of SMLP's independent registered public accounting firm due to a transition period established by rules of the SEC for newly publiccompanies.Item 9B. Other Information.On March 15, 2013, our Board granted 146,231 phantom units with distribution equivalent rights to certain key employees that provideservices to us, including executive officers, pursuant to the 2012 Long-Term Incentive Plan (the "LTIP"). Of the employee units, 34,629,15,391 and 14,429 phantom units were granted to Messrs. Newby, Harrison and Degeyter, respectively. The phantom units granted to thenamed executive officers in March of 2013 vest ratably over a three-year period, subject to accelerated vesting on the occurrence of any of thefollowing events: (i) a termination of the officer's employment other than for cause, (ii) a termination of the officer's employment by the officerfor good reason (as defined in the officer's employment agreement), (iii) a termination of the officer's employment by reason of the officer'sdeath or disability or (iv) a Change in Control (as defined in the applicable award agreement). Messrs. Newby, Harrison and Degeyterreceived distribution equivalent rights for each phantom unit, providing for a lump sum cash amount equal to the accrued distributions fromthe grant date of the phantom units to be paid in cash upon the vesting of such units. A form of the award agreement pursuant to which thesephantom units were granted is filed as exhibit 10.15 to this Annual Report on Form 10-K.71Table of ContentsPART IIIItem 10. Directors, Executive Officers and Corporate Governance.Management of Summit Midstream Partners, LPWe are managed by the directors and executive officers of our general partner, Summit Midstream GP, LLC. Our general partner is notelected by our unitholders and will not be subject to re-election in the future. Summit Investments, which is owned and controlled by EnergyCapital Partners and GE Energy Financial Services, is the sole owner of our general partner and has the right to appoint the entire board ofdirectors of our general partner, including our independent directors. All decisions of the board of directors of our general partner will requirethe affirmative vote of a majority of all of the directors constituting the board, provided that such majority includes at least a majority of thedirectors designated as an "Energy Capital Partner Designated Director" by Energy Capital Partners. The Energy Capital Partner DesignatedDirectors are Thomas K. Lane, Andrew F. Makk, Curtis A. Morgan and Jeffery R. Spinner. Our unitholders are not entitled to directly orindirectly participate in our management or operations. Our general partner is liable, as general partner, for all of our debts (to the extent notpaid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intendto incur indebtedness that is nonrecourse to our general partner.Our general partner's limited liability company agreement provides that the board of directors of our general partner must obtain the approvalof members representing a majority interest in our general partner for certain actions affecting us. These include actions related to:•transactions with affiliates;•entering into any hedging transactions that are not in compliance with Financial Accounting Standard 133;•the voluntary liquidation, wind-up or dissolution of us or any of our subsidiaries;•making any election that would result in us being classified as other than a partnership or a disregarded entity for U.S. federalincome tax purposes;•filing or consenting to the filing of any bankruptcy, insolvency or reorganization petition for relief from debtors or protection fromcreditors naming us or any of our subsidiaries; and•effecting a material amendment to our general partner's limited liability company agreement.Currently, Summit Investments is the sole member of our general partner. As long as Summit Investments is a member of our generalpartner, any approval of an action described in the above list must be evidenced by a resolution adopted by the board of managers of SummitInvestments.In connection with our initial public offering, Summit Investments and our general partner entered into an investor rights agreement with anaffiliate of GE Energy Financial Services. The investor rights agreement provided that GE Energy Financial Services or its affiliates couldelect to designate one director or one non-voting observer to the board of directors of our general partner for as long as the affiliate of GEEnergy Financial Services held at least a 10% limited liability company interest in Summit Investments. In October 2012, the investor rightsagreement terminated because the affiliate of GE Energy Financial Services' limited liability company interest in Summit Investments wasless than 10%. As a result, the affiliate of GE Energy Financial Services no longer has a right to appoint a director or a non-voting observer toour general partner's board of directors.Committees of the Board of DirectorsThe board of directors of our general partner has an audit committee (the "Audit Committee") and a conflicts committee (the "ConflictsCommittee") and may have such other committees as the board of directors shall determine from time to time.72Table of ContentsThe table below shows the current membership of each standing board committee.Name Audit Committee Conflicts Committee Independent DirectorThomas K. Lane NoAndrew F. Makk Member NoCurtis A. Morgan NoSteven J. Newby NoJerry L. Peters Chair Member YesJeffery R. Spinner NoSusan Tomasky Member Chair YesEach of the standing committees of the board of directors will have the composition and responsibilities described below.Audit Committee. Jerry L. Peters, Andrew F. Makk and Susan Tomasky serve as the members of the Audit Committee. Mr. Peters servesas the chair of our Audit Committee. In this role, Mr. Peters satisfies the SEC and New York Stock Exchange rules regarding independenceand qualifies as an audit committee financial expert.We are relying on the phase-in rules of the SEC and the New York Stock Exchange with respect to the independence of the Audit Committee.Those rules permit our general partner to have an audit committee that has one independent member upon the effectiveness of ourregistration statement, a majority of independent members within 90 days thereafter and all independent members within one yearthereafter. Our general partner is generally required to have at least three independent directors serving on its board at all times within oneyear after the effectiveness of our registration statement. In November 2012, Susan Tomasky was appointed to the board of directors of ourgeneral partner and to the Audit Committee. Prior to Ms. Tomasky's appointment, Mr. Thomas K. Lane served on the Audit Committee of ourgeneral partner. In compliance with the board transition rules, Mr. Makk will resign from the Audit Committee when the final independentdirector is appointed.The Audit Committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legaland regulatory requirements and corporate policies and controls. The Audit Committee has the sole authority to retain and terminate ourindependent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The Audit Committee is also responsible for confirmingthe independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm hasunrestricted access to the Audit Committee.Our audit committee has adopted an audit committee charter, which is available on our website at www.summitmidstream.com.Conflicts Committee. At the direction of our general partner, our Conflicts Committee will review specific matters that may involve conflictsof interest in accordance with the terms of our partnership agreement. The Conflicts Committee will determine if the resolution of the conflictof interest is in the best interests of our partnership. There is no requirement that our general partner seek the approval of the ConflictsCommittee for the resolution of any conflict. The members of the Conflicts Committee may not be officers or employees of our generalpartner or directors, officers, employees of any of its affiliates. They may not hold any ownership interest in our general partner or us and oursubsidiaries other than common units and other awards that are granted under our incentive plans in place from time to time. Furthermore,the members of the Conflicts Committee must meet the independence and experience standards established by the New York StockExchange and the Exchange Act to serve on an audit committee of a board of directors. Our Conflicts Committee will consist of one or moredirectors meeting these requirements. Mr. Peters and Ms. Tomasky serve as the members of our Conflicts Committee with Ms. Tomasky aschair of the committee. We anticipate that once appointed to our general partner's board of directors, the additional independent member(s)appointed to the Audit Committee will also serve on the Conflicts Committee.Any matters approved by the Conflicts Committee in good faith will be conclusively deemed to be approved by all of our partners and not abreach by our general partner of any duties it may owe us or our unitholders. Any unitholder challenging any matter approved by theConflicts Committee will have the burden of proving that the members of the Conflicts Committee did not subjectively believe that the matterwas in the best interests of our partnership. Moreover, any acts taken or omitted to be taken in reliance upon the advice or opinions of expertssuch as legal73Table of Contentscounsel, accountants, appraisers, management consultants and investment bankers, where our general partner (or any members of theboard of directors of our general partner including any member of the Conflicts Committee) reasonably believes the advice or opinion to bewithin such person's professional or expert competence, shall be conclusively presumed to have been taken or omitted in good faith.Directors and Executive OfficersDirectors are appointed for a term of one year and hold office until their successors have been elected or qualified or until the earlier of theirdeath, resignation, removal or disqualification. Officers serve at the discretion of the board of directors of our general partner. The followingtable shows information for the directors and executive officers of our general partner as of February 28, 2013.Name Age Position with Summit Midstream GP, LLCSteven J. Newby 40 President, Chief Executive Officer and DirectorMatthew S. Harrison 42 Senior Vice President and Chief Financial OfficerRene L. Casadaban 44 Senior Vice President, Engineering, Construction and Operations, SouthwestRegionBrock M. Degeyter 36 Senior Vice President and General CounselBrad N. Graves 46 Senior Vice President, Corporate DevelopmentJesse G. Wood 57 Senior Vice President, Engineering, Construction and Operations, Rockies RegionThomas K. Lane 56 DirectorAndrew F. Makk 43 DirectorCurtis A. Morgan 52 DirectorJerry L. Peters 55 DirectorJeffery R. Spinner 31 DirectorSusan Tomasky 59 DirectorSteven J. Newby has been the President and Chief Executive Officer of our general partner since May 2012. Mr. Newby was a foundingmember of Summit Midstream Partners, LLC and has been the President and Chief Executive Officer of Summit Midstream Partners, LLCsince its formation in September 2009. Mr. Newby's background includes over 17 years of oil and gas experience with a focus on themidstream sector of the energy industry. Mr. Newby was a founding member of SunTrust Bank's Corporate Energy industry specialty groupand ultimately became a Managing Director and Head of the Project Finance Group within SunTrust's Capital Markets division. In 2007, Mr.Newby joined ING Investment Management to manage a $300 million proprietary fund focused on the private and public investment in theenergy infrastructure space. Mr. Newby is a graduate of the University of North Carolina at Chapel Hill with a B.S. in BusinessAdministration with a concentration in Finance.Matthew S. Harrison has been the Senior Vice President and Chief Financial Officer of our general partner since May 2012. Prior to joiningour general partner, Mr. Harrison was the Senior Vice President and Chief Financial Officer of Summit Midstream Partners, LLC sinceSeptember 2011. Mr. Harrison's background includes over 14 years of energy and finance experience. Mr. Harrison joined SummitMidstream Partners, LLC from Hiland Partners, LP, where he served as Executive Vice President and Chief Financial Officer, Secretary andDirector from February 2008 to September 2011. Prior to joining Hiland, Mr. Harrison was a Director in the Energy & Power Merger &Acquisitions group at Wachovia Capital Markets from October 2007 to February 2008 and a Director in the Mergers & Acquisitions group atA.G. Edwards & Sons, Inc. from July 1999 to October 2007. Mr. Harrison was a Senior Accountant for Price Waterhouse for five years. Mr.Harrison received an MBA from Northwestern University—Kellogg Graduate School of Management in 1999 and a B.S. in Accounting fromthe University of Tennessee in 1992.Rene L. Casadaban has been the Senior Vice President of Engineering, Construction, and Operations of our general partner since May2012. Prior to joining our general partner, Mr. Casadaban was the Senior Vice President of Engineering, Construction and Operations ofSummit Midstream Partners, LLC from February 2011 until April 2012, and prior to that he served as a vice president from the time hejoined Summit Midstream Partners, LLC in November 2010. Mr. Casadaban has 20 years of project management experience for onshore,offshore and deepwater pipeline systems. Prior to joining Summit Midstream Partners, LLC, Mr. Casadaban worked for Enterprise ProductsPartners L.P. from 2006 to 2010 as the Director for Deepwater Development of floating74Table of Contentsproduction platforms and offshore pipelines. Mr. Casadaban has also served as an independent consultant to ExxonMobil and GulfTerra forGulf of Mexico and international pipeline projects. At Land & Marine, Mr. Casadaban was responsible for managing domestic andinternational pipeline river crossings and beach approaches by horizontal directional drilling. Mr. Casadaban is a graduate of AuburnUniversity with a B.S. in Building Construction.Brock M. Degeyter has been the Senior Vice President and General Counsel of our general partner since May 2012. Mr. Degeyter joinedSummit Midstream Partners, LLC in January 2012 as Senior Vice President and General Counsel. Mr. Degeyter's background includesover ten years of energy, finance and business law experience. Prior to joining our general partner, Mr. Degeyter worked in the corporate legaldepartment for Energy Future Holdings (formerly TXU Corp.) from January 2007 through December 2011 where he served as Director ofCorporate Governance and Senior Counsel. Prior to joining Energy Future Holdings, Mr. Degeyter was engaged in private practice with thefirm of Correro Fishman Haygood Phelps Walmsley & Casteix LLP from May 2002 through December 2006. Mr. Degeyter is licensed topractice law in the states of Texas and Louisiana. Mr. Degeyter received a B.A. in Political Science from Louisiana State University and a J.D.from Loyola University College of Law in New Orleans.Brad N. Graves has been the Senior Vice President of Corporate Development of our general partner since May 2012. In March 2013, hewas promoted to Chief Commercial Officer. Prior to joining our general partner, Mr. Graves was the Senior Vice President of CorporateDevelopment of Summit Midstream Partners, LLC since April 2010. He was previously a Partner with Crestwood Midstream Partners, LLCfrom February 2008 until March 2010. Mr. Graves has served as Executive Vice President—Business Development of Genesis Energy, LP(AMEX: GEL) from August 2006 until November 2007. He also served as Vice President—Offshore Commercial for Enterprise ProductsPartners L.P. (NYSE: EPD) from 2004 until August 2006. Prior to 2004, Mr. Graves served in a variety of commercial roles at EPD andGulfTerra Energy Partners, LP (NYSE: GTM), prior to its merger with EPD. In his roles with EPD and GTM, Mr. Graves participated innumerous greenfield projects developed in the Gulf of Mexico. Mr. Graves earned a B.B.A. in Accounting from Texas A&M University in 1989and an MBA in Marketing and Finance from the University of Saint Thomas in 1994.Jesse G. Wood began serving as Senior Vice President of Engineering, Construction, and Operations of our general partner in January2013, and prior to that he served as Vice President and Region Manager for the Rockies Region from the time that he joined SummitMidstream Partners, LLC in April 2012 until January 2013. Mr. Wood has over 32 years of experience working in the Rocky Mountain regiondeveloping, building, and operating midstream facilities. Prior to joining Summit Midstream Partners, LLC, Mr. Wood worked for nine yearsas the South Rockies Midstream Team Leader for Encana, executing and operating midstream projects in the DJ, Paradox, and Piceancebasins, where his teams developed midstream assets to support a 1.2 Bcf/d gathering system. Prior to that, Mr. Wood served for 20 yearswith Union Pacific Resources Company in a variety of engineering and leadership roles developing Rocky Mountain midstream facilities. Prior to 1983, Mr. Wood was employed by Duke Energy Field Services, where he served for four years as General Manager of thecompany's Rocky Mountain operations. Mr. Wood is a graduate of New Mexico State University, where he earned a bachelor's degree inChemical Engineering.Thomas K. Lane has served as a director of our general partner since May 2012 and was appointed to the board in connection with hisaffiliation with Energy Capital Partners, which controls our general partner. Mr. Lane has been a partner of Energy Capital Partners since2005. Prior to joining Energy Capital Partners, Mr. Lane worked for 17 years in the Investment Banking Division at Goldman Sachs. As aManaging Director at Goldman Sachs, Mr. Lane had senior-level coverage responsibility for electric and gas utilities, independent powercompanies and merchant energy companies throughout the United States. Mr. Lane received a B.A. in economics from Wheaton Collegeand an MBA from the University of Chicago. Mr. Lane was selected to serve as a director on the board due to his affiliation with EnergyCapital Partners, his knowledge of the energy industry and his financial and business expertise.Andrew F. Makk has served as a director of our general partner since May 2012 and was appointed to the board in connection with hisaffiliation with Energy Capital Partners, which controls our general partner. Mr. Makk has been a Principal at Energy Capital Partners since2005. Prior to joining Energy Capital Partners, he was a co-founder of a privately held energy company from 2002 to 2005, which built aportfolio of energy projects in Europe on behalf of a private equity fund. Prior to 2002, Mr. Makk spent nine years with Enron International invarious power and LNG asset development roles and became Head of Asset Development for Enron Europe in London. He received aB.S.M. in Finance from Tulane University and an MBA from the Fuqua School of Business at Duke University. Mr. Makk was selected toserve as a director on the board due to his affiliation with Energy Capital Partners, his knowledge of the energy industry and his financial andbusiness expertise.75Table of ContentsCurtis A. Morgan has served as a director of our general partner since May 2012 and was appointed to the board in connection with hisaffiliation with Energy Capital Partners, which controls our general partner. Mr. Morgan has served as the President and Chief ExecutiveOfficer of EquiPower Resources Corp. since May 2010. Prior to joining EquiPower Resources Corp., he served as an Operating Partner ofEnergy Capital Partners from May 2009 to May 2010. Prior to joining Energy Capital Partners, he served as President and Chief ExecutiveOfficer of FirstLight Power Enterprises from November 2006 to April 2009. Mr. Morgan has also held leadership positions at NRG Energy,Mirant Corporation and Reliant Energy. Mr. Morgan received a B.A. in Accounting from Western Illinois University and an MBA in Financeand Economics from the University of Chicago. He is a Certified Public Accountant. We believe that Mr. Morgan's extensive executive,financial and operational experience bring important and necessary skills to the board of directors.Jerry L. Peters has served as a director of our general partner since September 2012. Additionally, Mr. Peters served as the chair of theConflicts Committee of our general partner until Ms. Tomasky's appointment to the role in November 2012 and serves as the chair andfinancial expert of the Audit Committee of our general partner. Mr. Peters has served as the Chief Financial Officer of Green PlainsRenewable Energy, Inc., a publicly-traded vertically-integrated ethanol producer, since May 2007. Prior to that, Mr. Peters served as SeniorVice President—Chief Accounting Officer for ONEOK Partners, L.P. from May 2006 to April 2007, as Chief Financial Officer of ONEOKPartners, L.P. from July 1994 to May 2006, and in various senior management roles of ONEOK Partners, L.P. from 1985 to May 2006.Prior to joining ONEOK Partners, Mr. Peters was employed by KPMG LLP as a certified public accountant from 1980 to 1985. Mr. Petersreceived an MBA from Creighton University with an emphasis in finance and a B.S. in Business Administration from the University ofNebraska—Lincoln. We believe that Mr. Peters' extensive executive, financial and operational experience bring important and necessaryskills to the board of directors.Jeffrey R. Spinner has served as a director of our general partner since November 2012 and was appointed to the board in connection withhis affiliation with Energy Capital Partners, which controls our general partner. Mr. Spinner has been an investment professional at EnergyCapital Partners since 2006. Prior to joining Energy Capital Partners, Mr. Spinner worked in the Natural Resources Investment BankingGroup at Banc of America Securities. Mr. Spinner received a B.S. in Economics from Duke University.Susan Tomasky has served as a director of our general partner since November 2012. Additionally, Ms. Tomasky serves as the chair of theConflicts Committee of our general partner. Ms. Tomasky was a senior executive for 13 years at American Electric Power, one of the nation’slargest electric utilities, serving from 2009 to 2011 as President of the company’s transmission business, from 2007 through 2008 asExecutive Vice President for Shared Services, from 2001 until 2007 as Executive Vice President and Chief Financial Officer, and from 1998until 2001 as General Counsel. Ms. Tomasky currently serves as a director of two other public companies—Tesoro Corp. and Public ServiceEnterprise Group. Ms. Tomasky holds a juris doctorate degree from George Washington University National Law Center, and received herundergraduate degree from University of Kentucky in Lexington. Ms. Tomasky's extensive executive, financial, legal and regulatoryexperience bring important and necessary skills to the board of directors.Code of EthicsThe board of directors of our general partner has adopted a Code of Business Conduct and Ethics which sets forth SMLP’s policy with respectto business ethics and conflicts of interest. The Code of Business Conduct and Ethics is intended to ensure that the employees, officers anddirectors of SMLP conduct business with the highest standards of integrity and in compliance with all applicable laws and regulations. Itapplies to the employees, officers and directors of SMLP, including its principal executive officer, principal financial officer and principalaccounting officer or controller, or persons performing similar functions (the "Senior Financial Officers"). The Code of Business Conduct andEthics also incorporates expectations of the Senior Financial Officers that enable us to provide accurate and timely disclosure in our filingswith the SEC and other public communications. The Code of Business Conduct and Ethics is publicly available on our website under the"Corporate Governance" subsection of the Investors section at www.summitmidstream.com and is also available free of charge on request tothe Secretary at the Dallas office address given under the "Contact" section on our website.Section 16(a) Beneficial Owner Reporting ComplianceSection 16(a) of the Exchange Act requires SMLP's directors and executive officers, and persons who own more than 10% of a registeredclass of our securities, to file with the SEC initial reports of ownership and reports of changes in ownership of SMLP's common units andother equity securities. Based on our records, we believe that all directors, executive officers and persons who own more than 10% of ourcommon units have complied with the reporting requirements of Section 16(a), except that, due to an administrative oversight, the Form 3required in76Table of Contentsconnection with Susan Tomasky's addition to the board of directors of our general partner was not timely filed. On December 5, 2012, aForm 3 was filed to report that she did not own any Company securities on November 9, 2012, which is the date that she was appointed as adirector of our general partner.Item 11. Executive Compensation.Executive CompensationThe following describes the material components of our executive compensation program for the following individuals, who are referred to asthe "named executive officers":•Steven J. Newby, President and Chief Executive Officer;•Matthew S. Harrison, Senior Vice President and Chief Financial Officer; and•Brock M. Degeyter, Senior Vice President and General Counsel.The named executive officers are employees of Summit Investments and executive officers of our general partner. The named executiveofficers devote a majority of their working time to SMLP's business; however, they also maintain responsibilities for Summit Investmentsand its affiliates other than us. Under the terms of our partnership agreement, our general partner determines the portion of the namedexecutive officers' compensation that is allocated to us. For additional information, please refer to the discussion under the heading “Generaland Administrative Expense Allocation” in Item 13. Certain Relationships and Related Transactions, and Director Independence.Summary Compensation Table for 2012 and 2011. The following table sets forth certain information with respect to the compensationpaid to our named executive officers for the years ended December 31, 2012 and 2011. For 2012, the amounts shown in the summarycompensation table below generally reflect 100% of the compensation paid to the named executive officers by the Predecessor prior to ourIPO and the portion of the compensation paid to the named executive officers and allocated to SMLP for the period following our IPO. For2011, our general partner did not perform any such allocation of compensation costs, and the amounts shown in the summarycompensation table below for 2011 reflect 100% of the compensation paid by the Predecessor to our named executive officers.Name and Principal Position Year Salary ($) (1) Bonus ($)(2) Non-EquityIncentive PlanCompen-sation($)(3) Unit awards($)(4) All OtherCompen-sation($)(5) Total ($)Steven J. NewbyPresident and ChiefExecutive Officer 2012 $354,673 $— $393,738 $350,000 $7,500 $1,105,911 2011 295,500 250,000 — — 8,865 554,365Matthew S. HarrisonSenior Vice President andChief Financial Officer (6) 2012 $278,872 $— $236,332 $295,000 $27,116 $837,320 2011 87,176 240,000 — 911,000 — 1,238,176Brock M. DegeyterSenior Vice President,General Counsel (7) 2012 $221,983 $75,000 $231,635 $250,000 $5,097 $783,715 2011 — — — — — —___________(1) The amounts shown for 2012 represent that portion of the named executive officers' base salary paid by the Predecessor prior to the IPO andthe portion allocated to SMLP after the IPO. For a discussion of the cost allocation methodology, please refer to "General and AdministrativeExpenses Allocation" in Item 13 below.(2) For 2012, the amount relates to Mr. Degeyter's signing bonus, and for 2011, the amounts relate to discretionary bonuses to Messrs. Newby andHarrison, and also include Mr. Harrison's $25,000 signing bonus. The signing bonuses for Mr. Harrison and Mr. Degeyter were provided for intheir respective employment agreements and paid by the Predecessor as a result of their commencing employment with Summit Investments.(3) Represents incentive bonus earned under our annual incentive bonus program for the year ended December 31, 2012 and paid in March2013. For a discussion of the determination of these amounts, please read "—Elements of Compensation—Annual Incentive Compensation" below.The amounts shown for 2012 represent that portion of the named executive officers' annual bonus that has been allocated to SMLP. For adiscussion of the cost allocation methodology, please refer to "General and77Table of ContentsAdministrative Expenses Allocation" in Item 13 below. Prior to 2012, our named executive officers received discretionary bonuses.(4) Amounts shown in this column for 2012 for Messrs. Newby, Harrison and Degeyter reflect the grant date fair value of the phantom unit awardsgranted to the named executive officers in connection with the IPO, in accordance with FASB ASC Topic 718. For additional information, pleaserefer to "Elements of Compensation – Long-Term Equity Based Compensation Awards>' The amount shown in this column for 2011 for Mr. Harrisonreflects the grant date fair value of his pre-IPO equity awards in accordance with FASB ASC Topic 718. See Note 9 to the audited consolidatedfinancial statements for the assumptions made in valuing these awards.(5) Amounts shown in this column for 2012 and 2011 include employer contributions under the 401(k) Plan for all named executive officers. Also,pursuant to the terms of his employment agreement, the amount includes $19,616 for relocation expense reimbursement paid to Mr. Harrison in2012.(6) Mr. Harrison commenced employment with us on September 15, 2011. Amount shown for 2011 represents the base salary earned by Mr.Harrison for his partial year of employment in 2011.(7) Mr. Degeyter commenced employment with us on January 18, 2012. Amount shown for 2012 represents the base salary earned by Mr.Degeyter for his partial year of employment in 2012.Narrative Disclosure to Summary Compensation TableElements of Compensation. The primary elements of compensation for the named executive officers are base salary, annual incentivecompensation and long-term equity-based compensation awards. The named executive officers also receive certain retirement, health,welfare and additional benefits as described below.Base Salary. Base salaries for our named executive officers have generally been set at levels deemed necessary to attract and retainindividuals with superior talent. None of our named executive officers received any base salary adjustments or increases during 2012. Thebase salaries of our named executive officers, a portion of which are allocated to and reimbursed by the partnership, are set forth in thefollowing table:Name and Principal Position Base SalarySteven J. NewbyPresident and Chief Executive Officer $400,000Matthew S. HarrisonSenior Vice President and Chief Financial Officer 295,000Brock M. DegeyterSenior Vice President and General Counsel (1) 250,000___________(1) In March of 2013, Mr. Degeyter's base salary was adjusted upward to $265,000 to bring his salary in line with the current market.Annual Incentive Compensation. For 2012, Messrs. Newby, Harrison and Degeyter had target bonuses of $300,000, $221,250, $187,500respectively, or 75% of their base salaries. In March of 2013, Mr. Newby's target bonus opportunity was adjusted upward to 100% of his basesalary to bring it in line with the current market; however, the adjustment does not go into effect until the 2013 bonus year.Quantitative factors, as reflected in the corporate scorecard applicable to the senior leadership team (the "SLT Scorecard") determined one-halfof Messrs. Harrison and Degeyter's incentive compensation, while their respective business unit scorecards accounted for the remaininghalf. For Mr. Newby, the SLT Scorecard determined his entire annual incentive bonus for 2012.The SLT Scorecard contained seven objective factors related to the corporate enterprise's key objectives for 2012, including Adjusted EBITDAthresholds, operating expense and safety goals, capital projects, corporate growth and relative success of the company's initial public offering.Although we narrowly missed our adjusted EBITDA target for the year, we achieved or exceeded the performance measurement target on allof the other factors. As a result, Messrs. Newby, Harrison and Degeyter were awarded 114% of target for the portion of their bonuses basedon the SLT Scorecard.Mr. Newby's annual bonus payout was adjusted upward to $425,000, which is approximately 142% of his target bonus for 2012, primarilydue to his leadership in achieving strong operational results for our business, including strong safety, operational and cost performance, andhis significant contributions to the IPO and the company's other strategic transactions.78Table of ContentsMr. Harrison was awarded 100% of target for the portion of his bonus based on the performance of the finance and accounting business units.In total, Mr. Harrison's annual bonus payout was adjusted upward to $250,000, which is approximately 113% of his target bonus for 2012,primarily due to his significant contributions to the amendment and restatement of the revolving credit facility, the IPO, SummitInvestments' acquisition of the Red Rock Gathering system, and the company's successful integration of the Grand River system.Mr. Degeyter was awarded 127% of target for the portion of his bonus based on the performance of the legal business unit. In total, Mr.Degeyter's annual bonus payout was adjusted upward to $250,000, which is approximately 133% of his target bonus for 2012, primarily dueto his significant contributions to the IPO, Summit Investments' acquisition of the Red Rock Gathering system, and the company's variouslegal initiatives.Only a portion of the named executive officers' bonus amounts are allocated to and reimbursed by the Partnership. For a discussion of thecost allocation methodology, please refer to "G&A Expense Allocation" in Item 13 below.Long-Term Equity-Based Compensation Awards. In connection with our IPO, we adopted a new long-term equity incentive plan, whichis discussed in more detail under "2012 Long-Term Incentive Plan" below. In 2012, the Board granted 17,500, 14,750 and 12,500 phantomunits to Messrs. Newby, Harrison and Degeyter, respectively. The phantom units are expected to vest on the third anniversary of the pricingof our IPO, subject to accelerated vesting in limited circumstances. Messrs. Newby, Harrison and Degeyter received distribution equivalentrights for each phantom unit, providing for a lump sum cash amount equal to the accrued distributions from the grant date of the phantomunits to be paid in cash upon the vesting date.Retirement, Health and Welfare and Additional Benefits. The named executive officers are eligible to participate in such employeebenefit plans and programs as we may from time to time offer to our employees, subject to the terms and eligibility requirements of thoseplans. The named executive officers are eligible to participate in a tax-qualified 401(k) defined contribution plan to the same extent as all of ourother employees. In 2012, we made a fully vested contribution on behalf of each of the 401(k) plan's participants equal to 3% of suchparticipant's eligible salary for the year. Also, in 2012, pursuant to the terms of his employment agreement, Mr. Harrison was reimbursed$19,616 for relocation expenses.Outstanding Equity Awards at December 31, 2012The following table provides information regarding the phantom unit awards held by the named executive officers as of December 31, 2012.Name Number of phantom units that havenot vested (1) Market value of phantom units thathave not vested (2)Steven J. Newby 17,500 $347,025Matthew S. Harrison 14,750 292,493Brock M. Degeyter 12,500 247,875___________(1) All phantom units granted to the named executive officers in connection with the IPO vest on September 28, 2015, the third anniversary of thepricing of our IPO, subject to accelerated vesting on the occurrence of any of the following events: (i) a termination of the officer's employment otherthan for cause, (ii) a termination of the officer's employment by the officer for good reason (as defined in the officer's employment agreement), (iii) atermination of the officer's employment by reason of the officer's death or disability or (iv) a Change in Control (as defined in the applicable awardagreement).(2) Based on the closing price of SMLP's publicly traded common units on December 31, 2012.Employment and Severance Arrangements. Our named executive officers each have employment agreements with SummitInvestments.Mr. Newby's employment agreement, which was amended and restated as of August 13, 2012, has an initial term of three years, and isthen automatically extended for successive one-year periods, unless either party gives notice of non-extension to the other no later than 90days prior to the expiration of the then-applicable term. Mr. Newby's employment agreement provides for an annual base salary of $400,000,and a performance-based bonus ranging from 0% to 150% of base salary, with a target of 75% of base salary. In March of 2013, Mr. Newby'starget bonus opportunity was adjusted upward to 100% of his base salary. Mr. Newby is entitled to receive a prorated annual bonus (based ontarget) if his employment is terminated by the company without cause or due to death or disability. In addition, Mr. Newby's employmentagreement provides that the company will reimburse him for tax preparation services and ongoing tax advice up to $10,000 per year, as wellas an annual executive physical at a medical facility of his choice.79Table of ContentsMr. Newby's employment agreement provides for a cash severance payment upon a termination by the company without cause or by Mr.Newby for good reason, which is defined generally as the officer's termination of employment within two years after the occurrence of (i) amaterial diminution in the named executive officer's authority, duties or responsibilities, (ii) a material diminution in the officer's basecompensation, (iii) a material change in the geographic location at which the officer must perform his services under the agreement or (iv)any other action or inaction that constitutes a material breach of the employment agreement by the company (each a "QualifyingTermination"). In the event of a Qualifying Termination other than in the period beginning six months prior to a change in control of thecompany and ending on the 12-month anniversary of such a change in control, Mr. Newby's severance payment will be equal to the sum ofhis annual base salary and his annual bonus payable in respect of the immediately preceding year. If a Qualifying Termination occurs duringthe period beginning six months prior to a change in control and ending on the 12-month anniversary of such a change in control, Mr.Newby's severance payment will increase to two times the sum of his annual base salary and the immediately preceding year's bonus.Following any termination of employment other than one resulting from non-extension of the term, his employment agreement provides thatMr. Newby will be subject to a post-termination non-competition covenant through the severance period, and, following any termination ofemployment, Mr. Newby will be subject to a one-year post-termination non-solicitation covenant.If Mr. Newby's employment is terminated due to non-extension of the term, the company may choose to subject him to a non-competitioncovenant for up to one year post-termination. If the company exercises this "noncompete option", then Mr. Newby would be entitled to aseverance payment in an amount equal to the sum of his annual base salary and annual bonus payable in respect of the preceding year,multiplied by a fraction, the numerator of which is equal to the number of days from the date of termination through the expiration of therestricted period (as elected by us) and the denominator of which is 365. In this case, the severance payment will be payable in equalinstallments over the restricted period.Mr. Newby's employment agreement also provides that all equity awards granted to Mr. Newby under the LTIP and held by him as ofimmediately prior to a change in control of us will become fully vested immediately prior to the change in control.Mr. Newby's employment agreement provides that, if any portion of the payments or benefits provided to Mr. Newby would be subject to theexcise tax imposed in connection with Section 280G of the Internal Revenue Code, then the payments and benefits will be reduced if suchreduction would result in a greater after-tax payment to Mr. Newby.Mr. Harrison's employment agreement, dated September 15, 2011, has an initial term of two years, and is then automatically extended forsuccessive one-year periods, unless either party gives notice of non-extension to the other no later than 90 days prior to the expiration of thethen-applicable term. Mr. Harrison's employment agreement provides for an annual base salary of $295,000 and a performance-based bonusranging from 0% to 150% of base salary, with a target of 75% of base salary. Mr. Harrison's employment agreement also provides forreimbursement of up to $60,000 in relocation expenses incurred in relocating to Atlanta, Georgia, and reimbursement for tax preparationexpenses in the amount of $10,000 per year.Mr. Harrison's employment agreement also provides for a cash severance payment upon a termination by the company without cause or byMr. Harrison for good reason, which is defined generally as the officer's termination of employment within two years after the occurrence of (i)a material diminution in the named executive officer's authority, duties or responsibilities, (ii) a material diminution in the officer's basecompensation, (iii) a material change in the geographic location at which the officer must perform his services under the agreement or (iv)any other action or inaction that constitutes a material breach of the employment agreement by the company. Mr. Harrison's employmentagreement provides that the severance payment will be equal to the sum of his annual base salary and the annual bonus payable in respectof the preceding year, multiplied by a fraction, the numerator of which is equal to the number of days in the period beginning on the date oftermination and ending on the later of (a) the last day of the then-applicable term of the employment agreement and (b) the first anniversary ofthe date of termination (the "severance period") and the denominator of which is 365. The severance payment is payable in equalinstallments during the severance period.Following any termination of employment other than one resulting from non-extension of the term, the employment agreement provides thatMr. Harrison will be subject to a post-termination non-competition covenant through the severance period, and, following any termination ofemployment, Mr. Harrison will be subject to a one-year post-termination non-solicitation covenant.80Table of ContentsIf Mr. Harrison's employment is terminated due to non-extension of the term, the company may choose to subject him to a non-competitioncovenant for up to one year post-termination. If the company exercises this "noncompete option", then Mr. Harrison would be entitled to aseverance payment in an amount equal to the sum of his annual base salary and annual bonus payable in respect of the preceding year,multiplied by a fraction, the numerator of which is equal to the number of days from the date of termination through the expiration of therestricted period (as elected by the company) and the denominator of which is 365. In this case, the severance payment will be payable inequal installments over the restricted period.Mr. Degeyter's employment agreement, dated January 18, 2012, is substantially identical to Mr. Harrison's employment agreement, exceptthat it (i) provides for an annual base salary of $250,000, (ii) does not provide for reimbursement for relocation expenses or tax preparationservices, and (iii) does include a $75,000 cash signing bonus that was paid in March 2012, and a $75,000 cash retention bonus that waspaid in February 2013.2012 Long-Term Incentive PlanOur general partner approved the LTIP pursuant to which eligible officers (including the named executive officers), employees, consultantsand directors of our general partner and its affiliates are eligible to receive awards with respect to our equity interests, thereby linking therecipients' compensation directly to SMLP's performance. A total of 5,000,000 common units was reserved for issuance, pursuant to and inaccordance with its terms. The description of the LTIP set forth below is a summary of the material features of the LTIP; however it is not acomplete description of all of the provisions of the LTIP.The LTIP provides for the grant, from time to time at the discretion of the board of directors or compensation committee of our general partner,of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units andother unit-based awards. Subject to adjustment in the event of certain transactions or changes in capitalization, an aggregate of 125,000common units may be delivered pursuant to awards under the LTIP. Units that are canceled or forfeited will be available for delivery pursuantto other awards. The LTIP is administered by our general partner's board of directors, though such administration function may be delegatedto a committee (including the compensation committee) that may be appointed by the board to administer the LTIP. The LTIP is designed topromote our interests, as well as the interests of our unitholders, by rewarding eligible officers, employees, consultants and directors fordelivering desired performance results, as well as by strengthening our ability to attract, retain and motivate qualified individuals to serve asdirectors, consultants and employees.In 2012, the board of directors of our general partner granted 7,577 common units in the aggregate to three of our directors and granted125,000 phantom units with distribution equivalent rights to certain key employees that provide services for us, including executive officers,pursuant to the LTIP. Of the employee units, 17,500, 14,750 and 12,500 phantom units were granted to Messrs. Newby, Harrison andDegeyter, respectively. The phantom units granted to our named executive officers and other employees are expected to vest on the thirdanniversary of the consummation of our IPO, subject to accelerated vesting on the occurrence of any of the following events: (i) a terminationof the officer's employment other than for cause, (ii) a termination of the officer's employment by the officer for good reason (as defined in theofficer's employment agreement), (iii) a termination of the officer's employment by reason of the officer's death or disability or (iv) a Change inControl (as defined in the applicable award agreement). Holders of phantom units are entitled to receive distribution equivalent rights for eachphantom unit, providing for a lump sum cash amount equal to the accrued distributions from the grant date of the phantom units to be paid incash upon the vesting date.Restricted Units and Phantom Units. A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiturerestrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles thegrantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in thediscretion of the administrator, cash equal to the fair market value of a common unit. The administrator of the LTIP may make grants ofrestricted and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the administrator may determine areappropriate, including the period over which restricted or phantom units will vest. The administrator of the LTIP may, in its discretion, basevesting on the grantee's completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon achange of control (as defined in the LTIP) or as otherwise described in an award agreement.Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units.81Table of ContentsDistribution Equivalent Rights. The administrator of the LTIP, in its discretion, may also grant distribution equivalent rights, either asstandalone awards or in tandem with other awards. Distribution equivalent rights are rights to receive an amount in cash, restricted units orphantom units equal to all or a portion of the cash distributions made on units during the period an award remains outstanding.Source of Common Units; Cost. Common units to be delivered with respect to awards may be newly-issued units, common unitsacquired by us or our general partner in the open market, common units already owned by our general partner or us, common units acquiredby our general partner directly from us or any other person or any combination of the foregoing.Amendment or Termination of Long-Term Incentive Plan. The administrator of the LTIP, at its discretion, may terminate the LTIP at anytime with respect to the common units for which a grant has not previously been made. The LTIP will automatically terminate on the 10thanniversary of the date it was initially adopted by our general partner. The administrator of the LTIP will also have the right to alter or amendthe LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in anyoutstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant.Compensation Committee ReportAs our general partner does not have a compensation committee, the board of directors of our general partner provides the oversight,administers and makes decisions regarding our compensation policies and plans. Additionally, the board of directors of our general partnergenerally reviews and discusses the Compensation Discussion and Analysis with senior management of our general partner as a part of ourgovernance practices. Based on this review and discussion, the board of directors of our general partner has directed that the CompensationDiscussion and Analysis be included in this report for filing with the SEC.Members of the Board of Directors of Summit Midstream GP, LLCThomas K. Lane Andrew F. Makk Curtis A. MorganSteven J. Newby Jerry L. Peters Jeffery R. SpinnerSusan Tomasky Director CompensationMr. Morgan and the independent directors, which currently include Mr. Peters and Ms. Tomasky, each received a $50,000 annual retainer and$50,000 in annual unit compensation in 2012. These amounts were paid in conjunction with the individual's appointment to the board ofdirectors. In addition, for 2012, the following cash payments were approved:•the chairman of the Audit Committee received an additional annual retainer of $15,000;•the chairman of the Conflicts Committee received an additional annual retainer of $7,500;•each independent member of any committee (other than the chairman) received an additional annual retainer of $1,500;•and the chairman of any other committee is entitled to an annual retainer of $7,500.Board members are reconsidered for appointment on the one-year anniversary of their most recent appointment. We intend to paysubsequent retainers and compensation in connection with a member's reappointment to the board of directors. Our general partner did nothave any independent directors in 2011. We do not compensate employee directors for their services as directors.We reimburse all directors for travel and other related expenses in connection with attending board and committee meetings and board-related activities.82Table of ContentsThe following table shows the director compensation in 2012.Name Fees earned or paid incash Other fees Unit awards (1) TotalThomas K. Lane $— $— $— $—Andrew F. Makk — — — —Curtis A. Morgan 50,000 — 50,000 100,000Steven J. Newby — — — —Jerry L. Peters 50,000 16,500 50,000 116,500Jeffery R. Spinner — — — —Susan Tomasky 50,000 9,000 50,000 109,000___________(1) Amount shown represents the grant date fair value of the unit awards as determined in accordance with FASB ASC Topic 718. These unitawards were fully vested on the date of grant.Compensation Committee Interlocks and Insider ParticipationAs previously discussed, the Board is not required to maintain, and does not maintain a compensation committee.Mr. Newby, who serves as the President and Chief Executive Officer of our general partner, participates in his capacity as a director in thedeliberations of the Board concerning executive officer compensation. In addition, Mr. Newby makes recommendations to the Board regardingnamed executive officer compensation but abstains from any decisions regarding his compensation.Item 12. Security Ownership of Certain Beneficial Owners and Management and Related StockholderMatters.The following table sets forth certain information regarding the beneficial ownership of our common units as of February 28, 2013 and therelated transactions by:•each person who is known to us to beneficially own 5% or more of such units to be outstanding (based solely on Schedules 13D and13G filed with the SEC);•our general partner;•each of the directors and named executive officers of our general partner; and•all of the directors and executive officers of our general partner as a group.All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders as thecase may be.The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination ofbeneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a beneficial owner of a security if that person has orshares voting power, which includes the power to vote or to direct the voting of such security, or investment power, which includes the powerto dispose of or to direct the disposition of such security. In computing the number of common units beneficially owned by a person and thepercentage ownership of that person, common units subject to options or warrants held by that person that are currently exercisable orexercisable within 60 days of February 28, 2013, if any, are deemed outstanding, but are not deemed outstanding for computing thepercentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting andinvestment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.83Table of ContentsThe percentage of units beneficially owned is based on a total of 24,412,427 common units and 24,409,850 subordinated units outstandingas of February 28, 2013.Name Of Beneficial Owner Common UnitsBeneficiallyOwned Percentage ofCommon UnitsBeneficially Owned SubordinatedUnits BeneficiallyOwned Percentage ofSubordinated UnitsBeneficially Owned Percentage of TotalCommon andSubordinated UnitsBeneficially OwnedSummit Investments (1) (2) 10,029,850 41.1% 24,409,850 100.0% 70.5%Energy Capital Partners II, LLC (1) (3) (4) 10,029,850 41.1% 24,409,850 100.0% 70.5%Kayne Anderson Capital Advisors, L.P. (5) 1,506,214 6.2% — — 3.1%OppenheimerFunds, Inc. (6) 1,224,280 5.0% — — 2.5%Steven J. Newby (1) — — — — —Matthew S. Harrison (1) — — — — —Brock M. Degeyter (1) — — — — —Thomas K. Lane (4) (7) 40,000 * — — *Andrew F. Makk (4) — — — — —Curtis A. Morgan (8) 2,500 * — — *Jerry L. Peters (9) 2,500 * — — *Jeffery R. Spinner (4) — — — — —Susan Tomasky (10) 2,577 * — — *All directors and executive officers as a group(consisting of 12 persons) 47,577 * — — *________* An asterisk indicates that the person or entity owns less than one percent.(1)Summit Investments owns 100% of our general partner, 41.1% of our outstanding common units and 100.0% of our outstandingsubordinated units. Energy Capital Partners II, LLC ("ECP II") and its parallel and co-investment funds (the "ECP Funds" and togetherwith ECP II, "ECP") hold in the aggregate, an approximate 90.6% ownership interest in Summit Investments. ECP II is the generalpartner of the general partner of each of the ECP Funds that holds membership interests in Summit Investments and has voting andinvestment control over the securities held thereby. Accordingly, ECP may be deemed to indirectly beneficially own the 10,029,850common units and 24,409,850 subordinated units held by Summit Investments. The subordinated units held by Summit Investmentsmay be converted into common units on a one-for-one basis after expiration of the subordination period (as defined in the PartnershipAgreement).(2)The address for this person or entity is 2100 McKinney Avenue, Suite 1250, Dallas, Texas 75201.(3)ECP holds a 90.6% ownership interest in Summit Investments and may therefore be deemed to indirectly beneficially own the10,029,850 common units and 24,409,850 subordinated units held by Summit Investments. Because of its ownership interest inSummit Investments, ECP is entitled to elect four directors of Summit Investments. In addition, Thomas Lane (who is a managingmember of ECP II), Andrew Makk (who is a principal of ECP II) and Jeffery Spinner (who is employed by ECP II) are each directors ofour general partner. Neither Mr. Lane, Mr. Makk nor Mr. Spinner are deemed to beneficially own, and they disclaim beneficial ownershipof, any common units or subordinated units held by our general partner or Summit Investments.(4)The address for this person or entity is 51 John F. Kennedy Parkway, Suite 200, Short Hills, New Jersey 07078.(5)The address for this person or entity is 1800 Avenue of the Stars, 3rd Floor, Los Angeles, California 90067.(6)The address for this person or entity is Two World Financial Center, 225 Liberty Street, New York, New York 10281.84Table of Contents(7)Includes 20,000 common units held by Lane Ventures LLC ("Lane Ventures"). Two of Mr. Lane's estate planning trusts collectively owna majority of the membership interests in Lane Ventures and as a result, Mr. Lane may be deemed to indirectly beneficially own thecommon units held by Lane Ventures.(8)The address for this person or entity is 800 Long Ridge Road, Stamford, Connecticut 06927.(9)The address for this person is 450 Regency Parkway, Suite 400, Omaha, Nebraska 68114.(10)The address for this person is 90 Ashbourne Road, Bexley, Ohio 43209.Securities Authorized for Issuance Under Equity Compensation PlansThe following table provides information as of December 31, 2012 with respect to the Company's common units that may be issued underthe 2012 Long-Term Incentive Plan.Plan category Number of securities to beissued upon exercise ofoutstanding options, warrantsand rights(a) (1) Weighted-average exerciseprice of outstanding options,warrants and rights(b) Number of securitiesremaining available forfuture issuance under equitycompensation plans(excluding securitiesreflected in column (a))(c)Equity compensation plans approved by securityholders 125,000 n/a 4,868,423Equity compensation plans not approved by securityholders n/a n/a n/aTotal 125,000 n/a 4,868,423__________(1) Amount shown represents phantom unit awards outstanding under the LTIP at December 31, 2012. The awards are expected to be settled incommon units upon the applicable vesting date and are not subject to an exercise price.2012 Long-Term Incentive Plan. In connection with the IPO, our general partner approved the LTIP, pursuant to which eligible officers,employees, consultants and directors of our general partner and its affiliates are eligible to receive awards with respect to our equity interests.The LTIP is designed to promote our interests, as well as the interests of our unitholders, by rewarding eligible officers, employees,consultants and directors for delivering desired performance results, as well as by strengthening our ability to attract, retain and motivatequalified individuals to serve as directors, consultants and employees. A total of 5,000,000 common units was reserved for issuance,pursuant to and in accordance with the LTIP.The LTIP is administered by our general partner's board of directors. The LTIP provides for the grant, from time to time at the discretion of theboard of directors, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profitsinterest units and other unit-based awards. Units that are cancelled or forfeited are available for delivery pursuant to other awards.Common units to be delivered with respect to awards may be newly issued units, common units acquired by us or our general partner in theopen market, common units already owned by our general partner or us, common units acquired by our general partner directly from us orany other person or any combination of the foregoing.The general partner's board of directors, at its discretion, may terminate the LTIP at any time with respect to the common units for which agrant has not previously been made. The LTIP will automatically terminate on the 10th anniversary of the date it was initially adopted by ourgeneral partner. The general partner's board of directors also has the right to alter or amend the LTIP or any part of it from time to time or toamend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would materiallyimpair the rights of the participant without the consent of the affected participant.Item 13. Certain Relationships and Related Transactions, and Director Independence.As of December 31, 2012, Summit Investments owned 10,029,850 common units and 24,409,850 subordinated units, representing acombined 69.1% limited partner interest in us. In addition, Summit Investments owns and controls our general partner, which owns a 2.0%general partner interest in us and all of our incentive distribution rights.85Table of ContentsDistributions and Payments to our General Partner and its AffiliatesThe following summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with ourformation, ongoing operation and our liquidation. These distributions and payments were determined by and among affiliated entities and,consequently, are not the result of arm's-length negotiations.Formation StageThe consideration received by our general partner and its affiliates prior to or in connection with our IPO:•10,029,850 common units;•24,409,850 subordinated units;•all of our incentive distribution rights;•2.0% general partner interest; and•an $88.0 million cash payment from the proceeds of the offering.Operational StageDistributions of available cash to our general partner and its affiliates. We will initially make cash distributions 98.0% to ourunitholders pro rata, including Summit Investments, as the holder of an aggregate of 34,439,700 common units and subordinated units,and 2.0% to our general partner, assuming it makes any capital contributions necessary to maintain its 2.0% general partner interest in us.In addition, if distributions exceed the minimum quarterly distribution and target distribution levels, the incentive distribution rights held byour general partner will entitle our general partner to increasing percentages of the distributions, up to 48.0% of the distributions above thehighest target distribution level.Assuming we have sufficient cash available to pay the aggregate annualized minimum quarterly distribution on all of our outstanding unitsfor four quarters, our general partner and its affiliates would receive an annual distribution of approximately $1.6 million on its 2.0% generalpartner interest and Summit Investments would receive an annual distribution of approximately $55.1 million on its common units andsubordinated units.Payments to our general partner and its affiliates. Our general partner does not receive a management fee or other compensation for itsmanagement of us. Under our partnership agreement, we reimburse our general partner and its affiliates for certain expenses incurred onour behalf, including, without limitation, salary, bonus, incentive compensation and other amounts paid to our general partner's employeesand executive officers who perform services necessary to run our business. In addition, we reimburse our general partner for compensation,travel and entertainment expenses for the directors serving on the board of directors of our general partner and the cost of director and officerliability insurance. Our partnership agreement provides that our general partner determines in good faith the expenses that are allocable tous.Withdrawal or removal of our general partner. If our general partner withdraws or is removed, its general partner interest and itsincentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for anamount equal to the fair market value of those interests.Liquidation StageUpon our liquidation, our partners, including our general partner, will be entitled to receive liquidating distributions according to theirparticular capital account balances.Agreements with AffiliatesWe have various agreements with certain of our affiliates, as described below. These agreements have been negotiated among affiliatedparties and, consequently, are not the result of arm's-length negotiations.General and Administrative Expenses Allocation. Under our partnership agreement, we reimburse our general partner and its affiliatesfor certain expenses incurred on our behalf, including, without limitation, salary, bonus, incentive compensation and other amounts paid toour general partner's employees and executive officers who perform services necessary to run our business. In addition, we reimburse ourgeneral partner for compensation, travel and entertainment expenses for the directors serving on the board of directors of our general partnerand the cost of director and officer liability insurance. Our partnership agreement provides that our general partner will determine in good faiththe expenses that are allocable to us. Amounts paid to reimburse the general partner for these expenses were approximately $1.2 million in2012.86Table of ContentsElectricity Management Services Agreement. We entered into a consulting arrangement with Equipower Resources Corp., wherebythey assist DFW Midstream with managing its electricity price risk. Equipower Resources Corp. is an affiliate of our Sponsor, Energy CapitalPartners. Amounts paid for such services were as follows: Year ended December 31, 2012 2011 2010 (In thousands)Payments for electricity management consulting services$204 $11 $—Curtis A. Morgan, a member of the board of directors of our general partner, is the President and Chief Executive Officer of EquiPowerResources Corp.Promissory Notes Payable to Sponsors. In conjunction with the Grand River Transaction, Summit Investments executed $200.0million of promissory notes, on an unsecured basis, with its Sponsors. The notes had an 8% interest rate and were scheduled to mature inOctober 2013. In May 2012, Summit Holdings borrowed $163.0 million under the revolving credit facility and used a portion of the sameborrowings to prepay $160.0 million principal amount of the promissory notes payable to the Sponsors. Then in July 2012, an additional$50.0 million was borrowed under the revolving credit facility, a portion of which was used to pay the remaining $49.2 million principalamount of the promissory notes payable to Sponsors (inclusive of accrued pay-in-kind interest).In accordance with the terms of the underlying note agreement, prior to their repayment in July 2012, the Predecessor elected to make allinterest payments on the note in kind. The amount of interest paid in kind and accrued to the balance of the notes for year ended December31, 2012, was approximately $6.3 million, of which the Company capitalized $0.9 million of interest expense related to costs incurred oncapital projects under construction.DFW Class B Membership Interests. Certain current and former employees and members of management, or the DFW employees, ofDFW Management, hold Class B membership interests representing an aggregate 4.4% net profits interests in DFW Midstream. The netprofits interests allow the DFW employees to share in distributions by DFW Midstream only after we have received distributions in anamount equal to any capital contributions made subsequent to the date of grant, subject to the terms set forth in the underlying awardagreement and the limited liability company agreement of DFW Management.The net profits interests were granted subject to four-year vesting schedules, and provide for accelerated vesting in certain circumstances,including termination without cause or by reason of death or disability. Unvested profits interests are forfeited upon termination for any otherreason. Pursuant to the DFW Midstream limited liability company agreement, the vested net profits interests are subject to a repurchaseright, at our option, for one year following the holder's termination of employment. In the event of the termination of an employee'semployment due to death, disability, termination by DFW Midstream without cause or a voluntary resignation after the fourth anniversary ofthe employee's start date with DFW Midstream, the repurchase price will be equal to the value of the net profits interests in a hypotheticalliquidation of DFW Midstream pursuant to the rights and preferences set forth in the limited liability agreement, assuming all assets weresold for their fair market value.In August 2012, four former DFW employees filed a claim in the Court of Chancery of the State of Delaware relating to the net profitsinterests granted to them prior to their separation from DFW Midstream. For additional information, see Item 3. Legal Proceedings and Note11 to the audited consolidated financial statements.Review, Approval and Ratification of Related-Person TransactionsOn March 7, 2013, the board of directors of our general partner adopted a policy for the identification, review and approval of certain relatedperson transactions. The policy provides for the review and (as appropriate) approval by the Conflicts Committee of SMLP's general partner oftransactions between SMLP and its subsidiaries, on the one hand, and related persons (as that term is defined in SEC rules), on the otherhand. Pursuant to the policy, the General Counsel of SMLP's general partner is charged with primary responsibility for determining whether,based on the facts and circumstances, a proposed transaction is a related person transaction.For purposes of the policy, a "related person" is any director or executive officer of SMLP's general partner, any nominee for director, anyunitholder known to SMLP to be the beneficial owner of more than 5% of any class of the SMLP's common units, and any immediate familymember, affiliate or controlled subsidiary of any such person. A "related person transaction" is generally a transaction in which SMLP is, orSMLP's general partner or any of87Table of ContentsSMLP's subsidiaries is, a participant, where the amount involved exceeds $120,000, and a related person has a direct or indirect materialinterest. Transactions resolved under the conflicts provision of the partnership agreement are not required to be reviewed or approved underthe policy.If, after weighing all of the facts and circumstances, the general counsel of SMLP's general partner determines that a proposed transaction isa related person transaction that requires review or approval and the transaction meets certain monetary thresholds or involves certain relatedpersons, management must present the proposed transaction to the Conflicts Committee for advance approval. If the transaction does notmeet the designated monetary threshold or involve certain related persons, management presents the transaction(s) to the Committee fortheir review on a quarterly basis.The policy described above was adopted by the board of directors of our general partner on March 7, 2013, and as a result the transactionsdescribed in "—Agreements with Affiliates" above were not reviewed under such policy.Director IndependenceAlthough most companies listed on the New York Stock Exchange are required to have a majority of independent directors serving on theboard of directors of the listed company, the New York Stock Exchange does not require a listed limited partnership like us to have, and we donot intend to have, a majority of independent directors on the board of directors of our general partner.Item 14. Principal Accounting Fees and Services.Audit Fees. Our audit committee has ratified Deloitte & Touche LLP, Independent Registered Public Accounting Firm, to audit the books,records and accounts of SMLP for the year ended December 31, 2012. The fees billed by Deloitte & Touche LLP for the audit of consolidatedfinancial statements and other services rendered for the years ended December 31, 2012 and 2011 follow. Year ended December 31, 2012 2011Audit fees$1,602,276 $430,500Audit-related fees131,500 107,600Tax fees254,624 73,093All other fees (1)— 92,058Total$1,988,400 $703,251________(1) Fees related to IPO readiness project.Pre-approval Policy. Pursuant to its charter, the Audit Committee is responsible for the appointment, compensation, retention andoversight of SMLP's independent auditor (including resolution of disagreements between management and the independent auditorregarding financial reporting). The Audit Committee shall have sole authority to pre-approve all audit, audit-related and permitted non-auditengagements with the independent auditor, including the fees and other terms of such engagements. The independent auditor shall reportdirectly to the Audit Committee. The Audit Committee may consult with management but may not delegate these responsibilities tomanagement.88Table of ContentsPART IVItem 15. Exhibits, Financial Statement Schedules.(a)(1) Financial StatementsIncluded in Part II, Item 8, of this report:Summit Midstream Partners, LP and Subsidiaries:Report of Independent Registered Public Accounting FirmF-2Consolidated Balance Sheets as of December 31, 2012 and 2011F-3Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010F-4Consolidated Statements of Partners' Capital and Membership Interests for the years ended December 31, 2012, 2011 and 2010F-5Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010F-6Notes to Consolidated Financial StatementsF-8(2) Financial Statement SchedulesAll schedules are omitted because the required information is inapplicable or the information is presented in the financial statements or thenotes thereto.(3) Exhibit IndexAn “Exhibit Index” has been filed as part of this Report beginning on the following page and is incorporated herein by this reference.Schedules other than those listed above are omitted because they are not required, are not material, are not applicable, or the requiredinformation is shown in the financial statements or notes thereto.In reviewing the agreements included as exhibits to this annual report, please remember they are included to provide you with informationregarding their terms and are not intended to provide any other factual or disclosure information about the Company or the other parties to theagreements. The agreements contain representations and warranties by each of the parties to the applicable agreement. Theserepresentations and warranties have been made solely for the benefit of the other parties to the applicable agreement and:•should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties ifthose statements prove to be inaccurate;•have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement,which disclosures are not necessarily reflected in the agreement;•may apply standards of materiality in a way that is different from what may be viewed as material to you or other investors; and•were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and aresubject to more recent developments.Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any othertime.(b) Exhibit IndexExhibit number Description3.1 First Amended and Restated Agreement of Limited Partnership of Summit Midstream Partners, LP, dated as ofOctober 3, 2012 (Incorporated herein by reference to Exhibit 3.1 to SMLP's Current Report on Form 8-K datedOctober 4, 2012 (Commission File No. 001-35666))3.2 Amended and Restated Limited Liability Company Agreement of Summit Midstream GP, LLC, dated as of October3, 2012 (Incorporated herein by reference to Exhibit 3.2 to SMLP's Current Report on Form 8-K dated October 4,2012 (Commission File No. 001-35666))89Table of Contents3.3 Certificate of Limited Partnership of Summit Midstream Partners, LP (Incorporated herein by reference to Exhibit 3.1to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))3.4 Certificate of Formation of Summit Midstream GP, LLC (Incorporated herein by reference to Exhibit 3.4 to SMLP'sForm S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))4.1 Investor Rights Agreement, dated as of October 3, 2012, by and among EFS-S, LLC, Summit Midstream GP, LLCand Summit Midstream Partners, LLC (Incorporated herein by reference to Exhibit 4.1 to SMLP's Current Report onForm 8-K dated October 4, 2012 (Commission File No. 001-35666))10.1 Amendment and Restatement Agreement giving effect to the form of Amended and Restated Revolving CreditAgreement (Incorporated herein by reference to Exhibit 10.1 to SMLP's Form S-1 Registration Statement datedAugust 21, 2012 (Commission File No. 333-183466))10.2 Form of Amended and Restated Revolving Credit Agreement (included in Exhibit 10.1)10.3 Contribution, Conveyance and Assumption Agreement, dated as of October 3, 2012, by and among SummitMidstream GP, LLC, Summit Midstream Partners, LP, Summit Midstream Holdings, LLC and Summit MidstreamPartners, LLC (Incorporated herein by reference to Exhibit 10.1 to SMLP's Current Report on Form 8-K datedOctober 4, 2012 (Commission File No. 001-35666))10.4†Amended and Restated Natural Gas Gathering Agreement, dated August 1, 2010, by and between DFW MidstreamServices LLC, Chesapeake Energy Marketing, Inc., and Chesapeake Exploration, LLC (Incorporated herein byreference to Exhibit 10.6 to SMLP's Amendment No. 1 to its Form S-1 Registration Statement dated September 14,2012 (Commission File No. 333-183466))10.5†Amended and Restated Natural Gas Gathering Agreement, dated December 1, 2011, by and between DFWMidstream Services LLC and Carrizo Oil & Gas, Inc. (Incorporated herein by reference to Exhibit 10.7 to SMLP'sAmendment No. 1 to its Form S-1 Registration Statement dated September 14, 2012 (Commission File No. 333-183466))10.6†Second Amended and Restated Gas Gathering Agreement, dated November 1, 2010, by and between WillamsProduction RMT Company LLC and Encana Oil & Gas (USA) Inc. (Incorporated herein by reference to Exhibit 10.8to SMLP's Amendment No. 1 to its Form S-1 Registration Statement dated September 14, 2012 (Commission FileNo. 333-183466))10.7†Future Development Gas Gathering Agreement, dated October 1, 2011, by and between Encana Oil & Gas (USA)Inc., Grand River Gathering, LLC, and Summit Midstream Partners, LLC (Incorporated herein by reference toExhibit 10.9 to SMLP's Amendment No. 1 to its Form S-1 Registration Statement dated September 14, 2012(Commission File No. 333-183466))10.8†Mamm Creek Gas Gathering Agreement, dated October 1, 2011, by and between Encana Oil & Gas (USA) Inc.,Grand River Gathering, LLC, and Summit Midstream Partners, LLC (Incorporated herein by reference to Exhibit10.10 to SMLP's Amendment No. 1 to its Form S-1 Registration Statement dated September 14, 2012 (CommissionFile No. 333-183466))10.9*Amended and Restated Employment Agreement, dated August 13, 2012, by and between Summit MidstreamPartners, LLC and Steven J. Newby (Incorporated herein by reference to Exhibit 10.11 to SMLP's Form S-1Registration Statement dated August 21, 2012 (Commission File No. 333-183466))10.10*Employment Agreement, dated September 15, 2011, by and between Summit Midstream Partners, LLC andMatthew S. Harrison (Incorporated herein by reference to Exhibit 10.12 to SMLP's Amendment No. 1 to its Form S-1Registration Statement dated September 14, 2012 (Commission File No. 333-183466))10.11*Employment Agreement, dated January 18, 2012, by and between Summit Midstream Partners, LLC and Brock M.Degeyter (Incorporated herein by reference to Exhibit 10.13 to SMLP's Amendment No. 1 to its Form S-1Registration Statement dated September 14, 2012 (Commission File No. 333-183466))10.12*Amended and Restated Employment Agreement, dated March 8, 2013, by and between Summit MidstreamPartners, LLC and Brad N. Graves10.13*Employment Agreement, dated September 19, 2012, by and between Summit Midstream Partners, LLC and ReneCasadaban (Incorporated herein by reference to Exhibit 10.15 to SMLP's Amendment No. 2 to its Form S-1Registration Statement dated September 20, 2012 (Commission File No. 333-183466))90Table of Contents10.14*Summit Midstream Partners, LP 2012 Long-Term Incentive Plan (Incorporated herein by reference to Exhibit 10.2 toSMLP's Current Report on Form 8-K dated October 4, 2012 (Commission File No. 001-35666))10.15 Form of Phantom Unit Award Agreement (Incorporated herein by reference to Exhibit 10.5 to SMLP's Form S-1Registration Statement dated August 21, 2012 (Commission File No. 333-183466))10.16 Form of Director Unit Award Agreement (Incorporated herein by reference to Exhibit 10.3 to SMLP's Current Reporton Form 8-K dated October 4, 2012 (Commission File No. 001-35666))23.1 Consent of Deloitte & Touche LLP31.1†Rule 13a-14(a)/15d-14(a) Certification, executed by Steven J. Newby, President, Chief Executive Officer and Director31.2†Rule 13a-14(a)/15d-14(a) Certification, executed by Matthew S. Harrison, Senior Vice President and Chief FinancialOfficer32.1†Certifications required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the UnitedStates Code (18 U.S.C. 1350), executed by Steven J. Newby, President, Chief Executive Officer and Director, andMatthew S. Harrison, Senior Vice President and Chief Financial Officer101.INS**XBRL Instance Document (1)101.SCH**XBRL Taxonomy Extension Schema101.CAL**XBRL Taxonomy Extension Calculation Linkbase101.DEF**XBRL Taxonomy Extension Definition Linkbase101.LAB**XBRL Taxonomy Extension Label Linkbase101.PRE**XBRL Taxonomy Extension Presentation Linkbase* Management contract or compensatory plan or arrangement required to be filed as an exhibit pursuant to Item 15(b) of this report† Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been filed separately with theSecurities and Exchange Commission.** Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registrationstatement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes ofSection 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections. Thefinancial information contained in the XBRL(eXtensible Business Reporting Language)-related documents is unaudited and unreviewed.(1) Includes the following materials contained in this Annual Report on Form 10-K for the year ended December 31, 2012, formatted inXBRL: (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Partners' Capital andMembership Interests, (iv) Consolidated Statements of Cash Flows, and (v) Notes to Consolidated Financial Statements.(c) Financial Statement SchedulesNot applicable.91Table of ContentsSIGNATURESPursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to besigned on its behalf by the undersigned, thereunto duly authorized. Summit Midstream Partners, LP (Registrant) March 18, 2013By: Summit Midstream GP, LLC (its general partner) /s/ Matthew S. Harrison Matthew S. Harrison, Senior Vice President and Chief FinancialOfficerPursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf ofthe registrant and in the capacities and on the dates indicated.Signature Title Date/s/ Steven J. Newby Director, President and Chief Executive Officer (PrincipalExecutive Officer) March 18, 2013Steven J. Newby /s/ Matthew S. Harrison Senior Vice President and Chief Financial Officer(Principal Financial and Accounting Officer) March 18, 2013Matthew S. Harrison /s/ Thomas K. Lane Director March 18, 2013Thomas K. Lane /s/ Andrew F. Makk Director March 18, 2013Andrew F. Makk /s/ Curtis A. Morgan Director March 18, 2013Curtis A. Morgan /s/ Jerry L. Peters Director March 18, 2013Jerry L. Peters /s/ Jeffery R. Spinner Director March 18, 2013Jeffery R. Spinner /s/ Susan Tomasky Director March 18, 2013Susan Tomasky 92Table of ContentsIndex to Financial StatementsReport of Independent Registered Public Accounting FirmF-2Consolidated Balance Sheets as of December 31, 2012 and 2011F-3Consolidated Statements of Operations for years ended December 31, 2012, 2011 and 2010F-4Consolidated Statements of Partners' Capital and Membership Interests for the years ended December 31, 2012, 2011 and 2010F-5Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010F-6Notes to Consolidated Financial StatementsF-8F-1Table of ContentsREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTo the Board of Directors of Summit Midstream GP, LLC and the unitholders of Summit Midstream Partners, LPDallas, TexasWe have audited the accompanying consolidated balance sheets of Summit Midstream Partners, LP and subsidiaries (the "Partnership") asof December 31, 2012 and 2011, and the related consolidated statements of operations, partners' capital and membership interests, and cashflows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of thePartnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Thosestandards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free ofmaterial misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financialreporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that areappropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal controlover financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting theamounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made bymanagement, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for ouropinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Summit MidstreamPartners, LP and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of thethree years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States ofAmerica.As discussed in Note 3 to the consolidated financial statements, the Partnership acquired Grand River Gathering Company, LLC on October27, 2011./s/ Deloitte & Touche LLPDallas, TexasMarch 18, 2013F-2Table of ContentsSUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS December 31, 2012 2011 (Dollars in thousands)Assets Current assets: Cash and cash equivalents$7,895 $15,462Accounts receivable33,504 27,476Receivable from affiliate774 —Other assets2,190 1,966Total current assets44,363 44,904Property, plant and equipment, net681,993 638,190Intangible assets, net: Favorable gas gathering contract19,958 21,673Contract intangibles229,596 242,238Rights-of-way35,986 32,802Total intangible assets, net285,540 296,713Goodwill45,478 45,478Other noncurrent assets6,137 4,979Total assets$1,063,511 $1,030,264 Liabilities and Partners' Capital and Membership Interests Current liabilities: Trade accounts payable$15,817 $21,485Deferred revenue865 —Ad valorem taxes payable5,455 2,383Other current liabilities4,324 4,971Total current liabilities26,461 28,839Promissory notes payable to Sponsors— 202,893Revolving credit facility199,230 147,000Noncurrent liability, net (Note 5)7,420 8,944Deferred revenue10,899 1,770Other noncurrent liabilities254 —Total liabilities244,264 389,446Commitments and contingencies (Note 11) Common limited partner capital (24,412,427 units issued and outstanding at December 31, 2012)418,856 —Subordinated limited partner capital (24,409,850 units issued and outstanding at December 31, 2012)380,169 —General partner interests (996,320 units issued and outstanding at December 31, 2012)20,222 —Membership interests— 640,818Total partners' capital and membership interests819,247 640,818Total liabilities and partners' capital and membership interests$1,063,511 $1,030,264The accompanying notes are an integral part of these consolidated financial statements.F-3Table of ContentsSUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF OPERATIONS Year ended December 31, 2012 2011 2010 (In thousands, except per-unit and unit amounts)Revenues: Gathering services and other fees$149,371 $91,421 $29,358Natural gas and condensate sales16,320 12,439 2,533Amortization of favorable and unfavorable contracts(192) (308) (215)Total revenues165,499 103,552 31,676 Costs and expenses: Operation and maintenance51,658 29,855 9,503General and administrative21,357 17,476 10,035Transaction costs2,020 3,166 —Depreciation and amortization35,299 11,367 3,874Total costs and expenses110,334 61,864 23,412Other income9 12 32Interest expense(7,340) (1,029) —Affiliated interest expense(5,426) (2,025) —Income before income taxes42,408 38,646 8,296Income tax expense(682) (695) (124)Net income41,726 37,951 8,172Net income attributable to noncontrolling interest— — 78Net income attributable to SMLP$41,726 $37,951 $8,094Less: net income attributable to the pre-IPO period24,112 Net income attributable to the post-IPO period17,614 Less: net income attributable to general partner352 Net income attributable to limited partners$17,262 Earnings per common unit – basic$0.35 Earnings per common unit – diluted$0.35 Earnings per subordinated unit – basic and diluted$0.35 Weighted-average common units outstanding – basic24,412,427 Weighted-average common units outstanding – diluted24,543,985 Weighted-average subordinated units outstanding – basic and diluted24,409,850 The accompanying notes are an integral part of these consolidated financial statements.F-4Table of ContentsSUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL AND MEMBERSHIP INTERESTS Partners' capital Limited partners Non-controllinginterest Common Subordinated General partner Membershipinterests Total (In thousands)Membership interests,January 1, 2010$— $— $— $130,268 $54,798 $185,066Net income— — — 8,094 78 8,172Contributions— — — 194,134 10,720 204,854Purchase of interest insubsidiary fromnoncontrolling interest— — — (25,126) (65,596) (90,722)Membership interests,December 31, 2010— — — 307,370 — 307,370Net income— — — 37,951 — 37,951Class B unit-basedcompensation—— — 3,440 — 3,440Contributions from Sponsors— — — 425,000 — 425,000Distribution of cash toSponsor— — — (132,943) — (132,943)Membership interests,December 31, 2011— — — 640,818 — 640,818Net income8,631 8,631 352 24,112 — 41,726SMLP unit-basedcompensation269 — — — — 269Class B unit-basedcompensation(186) — — 1,793 — 1,607Net assets retained by thePredecessor— — — (4,417) — (4,417)Contribution of net assets toSMLP211,938 430,498 19,870 (662,306) — —Issuance of common units,net of offering costs262,382 — — — — 262,382Distribution of proceeds fromoffering(64,178) (58,960) — — — (123,138)Partners' capital, December31, 2012$418,856 $380,169 $20,222 $— $— $819,247The accompanying notes are an integral part of these consolidated financial statements.F-5Table of ContentsSUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS Year ended December 31, 2012 2011 2010 (In thousands)Cash flows from operating activities: Net income$41,726 $37,951 $8,172Adjustments to reconcile net income to cash provided by operatingactivities: Depreciation and amortization35,299 11,367 3,874Amortization of favorable and unfavorable contracts192 308 215Amortization of deferred loan costs1,458 560 —Pay in kind interest on promissory notes payable to Sponsors5,426 2,025 —SMLP unit-based compensation269 — —Class B membership interest unit-based compensation expense1,607 3,440 —Changes in operating assets and liabilities: Accounts receivable(6,028) (17,238) (8,865)Receivable from affiliate(774) — —Other assets(239) (1,707) 125Trade accounts payable(2,164) 2,468 4,210Change in deferred revenue9,994 — —Ad valorem taxes payable3,072 — —Other current liabilities(604) 768 1,822Other noncurrrent liabilities254 — —Net cash provided by (used in) operating activities89,488 39,942 9,553 Cash flows from investing activities: Capital expenditures(76,698) (78,248) (153,719)Acquisition of Grand River Gathering— (589,462) —Net cash provided by (used in) investing activities(76,698) (667,710) (153,719) Cash flows from financing activities: Proceeds from issuance of common units, net263,125 — —Contributions from Sponsors— 425,000 194,134Distributions to Sponsors(123,138) (132,943) —Borrowings under revolving credit facility213,000 147,000 —Repayments under revolving credit facility(160,770) — —Deferred loan costs(3,344) (5,248) —(Repayment of) proceeds from promissory notes payable to Sponsors(209,230) 200,000 —Purchase of interest in subsidiary from noncontrolling interest— — (90,722)Contributions from noncontrolling interest— — 10,720Net cash provided by (used in) financing activities(20,357) 633,809 114,132Net change in cash and cash equivalents(7,567) 6,041 (30,034)Cash and cash equivalents, beginning of period15,462 9,421 39,455Cash and cash equivalents, end of period$7,895 $15,462 $9,421The accompanying notes are an integral part of these consolidated financial statements.F-6Table of ContentsSUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS - continued Year ended December 31, 2012 2011 2010 (In thousands)Supplemental Schedule of Investing and Financing Activities: Cash interest paid$8,283 $2,463 $—Capitalized interest(2,784) (3,362) — Interest paid (net of capitalized interest)$5,499 $(899) $— Cash paid for taxes$650 $223 $10 Supplemental Disclosures of Noncash Investing and FinancingActivities: Capital expenditures in accounts payable (period-end accruals)$7,829 $11,332 $12,958Pay-in-kind interest6,337 2,893 —Unit-based compensation1,876 3,440 —IPO costs incurred in 2011743 — —Net assets retained by the Predecessor4,417 — —Working capital acquired related to Grand River system acquisition— 854 —The accompanying notes are an integral part of these consolidated financial statements.F-7Table of ContentsSUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS1. ORGANIZATION AND BUSINESS OPERATIONSOrganization. Summit Midstream Partners, LP ("SMLP" or the "Partnership"), a Delaware limited partnership, was formed in May 2012and began operations in October 2012 in connection with its initial public offering ("IPO") of common limited partner units. SMLP is agrowth-oriented limited partnership focused on owning and operating midstream energy infrastructure assets that are strategically located inthe core producing areas of unconventional resource basins, primarily shale formations, in North America.Summit Midstream Partners, LLC ("Summit Investments") is a Delaware limited liability company and the predecessor for accountingpurposes (the "Predecessor") of SMLP. Summit Investments was formed and began operations on September 3, 2009. Through August2011, Summit Investments was wholly owned by Energy Capital Partners II, LLC and its parallel and co-investment funds (collectively,"Energy Capital Partners"). In August 2011, Energy Capital Partners sold an interest in Summit Investments to a subsidiary of GE EnergyFinancial Services, Inc. ("GE Energy Financial Services", and collectively with Energy Capital Partners, the "Sponsors").SMLP is managed and operated by the board of directors and executive officers of Summit Midstream GP, LLC (the "general partner").Summit Investments, which is owned and controlled by Energy Capital Partners and GE Energy Financial Services, is the sole owner ofour general partner and has the right to appoint the entire board of directors of our general partner, including our independent directors.SMLP's operations are conducted through, and our operating assets are owned by, various operating subsidiaries. However, neither SMLPnor its subsidiaries have any employees. The general partner has the sole responsibility for providing the personnel necessary to conductSMLP's operations, whether through directly hiring employees or by obtaining the services of personnel employed by others, includingSummit Investments. All of the personnel that conduct SMLP's business are employed by the general partner and its affiliates, but theseindividuals are sometimes referred to as our employees.References to the "Company," "we," or "our," when used for dates or periods ended on or after the IPO, refer collectively to SMLP and itssubsidiaries. References to the "Company," "we," or "our," when used for dates or periods ended prior to the IPO, refer collectively toSummit Investments and its subsidiaries.Initial Public Offering. On October 3, 2012, SMLP completed its IPO and the following transactions occurred:•Summit Investments conveyed an interest in Summit Midstream Holdings, LLC ("Summit Holdings") to our general partner as acapital contribution;•our general partner conveyed its interest in Summit Holdings to SMLP in exchange for (i) a continuation of its 2% general partnerinterest in SMLP, represented by 996,320 general partner units, and (ii) SMLP incentive distribution rights, or IDRs;•Summit Investments conveyed its remaining interest in Summit Holdings to SMLP in exchange for (i) 10,029,850 common units(net of the impact of selling 1,875,000 common units to the public for cash in connection with the exercise of the underwriters’ optionto purchase additional common units), representing a 20.1% limited partner interest in SMLP, (ii) 24,409,850 subordinated units,representing a 49.0% limited partner interest in SMLP, and (iii) the right to receive $88.0 million in cash as reimbursement forcertain capital expenditures made with respect to the contributed assets;•pursuant to its long-term incentive plan, SMLP granted 5,000 common units (in the aggregate) to two of its directors and 125,000phantom units, with distribution equivalent rights, to certain employees;•SMLP issued 14,375,000 common units to the public (including 1,875,000 additional common units sold out of the common unitsoriginally allocated to Summit Investments) representing a 28.9% limited partner interest in SMLP; and•SMLP used the proceeds, net of underwriters’ fees, from the IPO of approximately $269.4 million to (i) repay $140.0 millionoutstanding under the revolving credit facility; (ii) make cash distributions to Summit Investments of (a) $88.0 million to reimburseSummit Investments for certain capital expenditures it incurred with respect to assets it contributed to us and (b) $35.1 millionrepresenting the funds received in connection with the underwriters exercising their option to purchase additional common units;and (iii) pay IPO expenses of approximately $6.3 million.F-8Table of ContentsUpon conclusion of the above transactions, SMLP has a 100% ownership interest in Summit Holdings, which has a 100% ownershipinterest in both DFW Midstream Services LLC ("DFW Midstream") and Grand River Gathering, LLC ("Grand River Gathering"). The effectsof the IPO and related equity transfers occurring in October 2012 are reflected in SMLP's financial statements.Business Operations. We provide natural gas gathering and compression services pursuant to long-term, fee-based natural gas gatheringagreements with our customers. Our results are driven primarily by the volumes of natural gas that we gather and compress across oursystems and a significant percentage of our revenue is attributable to three producer customers and one natural gas marketer. We currentlyoperate in two unconventional resource basins:•the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado;and•the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas.Our two operating subsidiaries are DFW Midstream and Grand River Gathering. Both subsidiaries are midstream energy companiesfocused on the development, construction and operation of natural gas gathering systems.In October 2011, we acquired Grand River Gathering. Grand River Gathering owns certain natural gas gathering pipeline, dehydration andcompression assets located in the Piceance Basin. These assets gather production from the Mamm Creek, Orchard, and South Parachutefields in the area around Rifle, Colorado. In addition to the purchase, we have a contractual relationship with the seller related to thedevelopment of midstream infrastructure to support the seller’s emerging Mancos and Niobrara shale developments. See Note 3.Concurrent with Summit Investments' formation in September 2009, we acquired a controlling interest in DFW Midstream. In June 2010,we purchased the remaining noncontrolling interest in DFW Midstream. DFW Midstream owns certain natural gas gathering pipeline andcompression assets located in the Fort Worth Basin.Basis of Presentation and Principles of Consolidation. We prepare our consolidated financial statements in accordance with accountingprinciples generally accepted in the United States of America ("GAAP"). These principles are established by the Financial AccountingStandards Board. We make estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates,including fair value measurements, the reported amounts of revenue and expense, and disclosure of contingencies. Although managementbelieves these estimates are reasonable, actual results could differ from its estimates.For the purposes of these consolidated financial statements, SMLP's results of operations reflect the Partnership's operations subsequent tothe IPO and the results of the Predecessor for the period prior to the IPO. The consolidated financial statements include the assets, liabilities,and results of operations of SMLP or the Predecessor and their wholly owned subsidiaries Summit Holdings, DFW Midstream and GrandRiver Gathering. All intercompany transactions among the consolidated entities have been eliminated.Our operations are organized into a single reportable segment, the assets of which consist of natural gas gathering systems and related plantand equipment. In 2012 and 2011, the consolidated financial statements include the operations of Grand River Gathering. See Note 3.Reclassifications. Certain reclassifications have been made to prior-year amounts to conform to current-year presentation. Thesereclassifications had no impact on net income or total partners' capital or membership interests.2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIESCash and Cash Equivalents. Cash and cash equivalents include temporary cash investments with original maturities of three months orless.Accounts Receivable. Accounts receivable relate to gathering and other services provided to our natural gas producer customers. To theextent we doubt the collectability of our accounts receivable, we recognize an allowance for doubtful accounts. We did not experience non-payment for services during the three-year period ended December 31, 2012. As a result, we did not recognize an allowance for doubtfulaccounts as of December 31, 2012 and 2011.Property, Plant, and Equipment. We record property, plant, and equipment at historical cost of construction or fair value of the assets atacquisition. We capitalize expenditures that extend the useful life of an asset or enhance its productivity or efficiency from its original designover the expected remaining period of use. For maintenance and repairs that do not add capacity or extend the useful life of an asset, werecognize expenditures as incurred. WeF-9Table of Contentscapitalize project costs incurred during construction, including interest on funds borrowed to finance the construction of facilities, asconstruction in progress.We base an asset’s carrying value on estimates, assumptions and judgments for useful life and salvage value. We record depreciation on astraight-line basis over an asset’s estimated useful life. We base our estimates for useful life on various factors including age (in the case ofacquired assets), manufacturing specifications, technological advances, and historical data concerning useful lives of similar assets.Upon sale or retirement, we remove the carrying value of an asset and its accumulated depreciation from our balance sheet and recognizethe related gain or loss, if any.Asset Retirement Obligations. We record a liability for asset retirement obligations only if and when a future asset retirement obligationwith a determinable life is identified. As of December 31, 2012 and 2011, we evaluated whether any future asset retirement obligationsexisted. For identified asset retirement obligations, we then evaluated whether the expected retirement date of the related costs of retirementcould be estimated. In performing this evaluation, we concluded that our natural gas gathering system assets have an indeterminate lifebecause they are owned and will operate for an indeterminate future period when properly maintained. Because we did not have sufficientinformation to reasonably estimate the amount or timing of such obligations and we have no current plan to discontinue use of anysignificant assets, we did not provide for any asset retirement obligations as of December 31, 2012 or 2011.Intangible Assets and Noncurrent Liability. Upon the acquisition of DFW Midstream, certain of our gas gathering contracts were deemedto have above-market pricing structures while another was deemed to have pricing that was below market. We have recognized the contractsthat were above market at acquisition as favorable gas gathering contracts. We have recognized the contract that was deemed to be belowmarket as a noncurrent liability. We amortize these intangibles on a units-of-production basis over the estimated useful life of the contract. Wedefine useful life as the period over which the contract is expected to contribute directly or indirectly to our future cash flows. The relatedcontracts have original terms ranging from 10 years to 20 years. We recognize the amortization expense associated with these intangibleassets and liabilities in revenue.For Grand River Gathering gas gathering contracts, we amortize contract intangible assets over the period of economic benefit based uponthe expected revenues over the life of the contract. The useful life of these contracts ranges from 10 years to 25 years. We recognize theamortization expense associated with these intangible assets in depreciation and amortization expense.We have right-of-way intangible assets associated with city easements and easements granted within existing rights-of-way. We amortizethese intangible assets over the shorter of the contractual term of the rights-of-way or the estimated useful life of the gathering system. Thecontractual terms of the rights-of-way range from 20 years to 30 years. The estimated useful life of our gathering systems is 30 years. Werecognize the amortization expense associated with these intangible assets in depreciation and amortization expense.Impairment of Long-Lived Assets. We test assets for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cashflows expected to result from its use and eventual disposition. If we conclude that an asset’s carrying value will not be recovered throughfuture cash flows, we recognize an impairment loss on the long-lived asset equal to the amount by which the carrying value exceeds its fairvalue. We determine fair value using an income approach in which we discount the asset’s expected future cash flows to reflect the riskassociated with achieving the underlying cash flows. During the three-year period ended December 31, 2012, we concluded that none of ourlong-lived assets had been impaired.Goodwill. Goodwill represents consideration paid in excess of the fair value of the net identifiable assets acquired in a business combination.We evaluate goodwill for impairment annually on September 30. We also evaluate goodwill whenever events or circumstances indicate thatit is more likely than not that the fair value of a reporting unit is less than its carrying amount.We test goodwill for impairment using a two-step quantitative test. In the first step, we compare the fair value of the reporting unit to itscarrying value, including goodwill. If the reporting unit’s fair value exceeds its carrying amount, we conclude that the goodwill of the reportingunit has not been impaired and no further work is performed. If we determine that the reporting unit’s carrying value exceeds its fair value,we proceed to step two. In step two, we compare the carrying value of the reporting unit to its implied fair value. If we determine that thecarrying amount of a reporting unit's goodwill exceeds its implied fair value, we recognize the excess of the carrying value over the impliedfair value as an impairment loss.F-10Table of ContentsOther Noncurrent Assets. Other noncurrent assets primarily consist of external costs incurred in connection with the closing of ourrevolving credit facility. We capitalize and then amortize deferred loan costs over the life of the revolving credit facility. We recognizeamortization of deferred loan costs in interest expense. As of December 31, 2011, other noncurrent assets also included costs incurred inpreparation for our IPO, however, such amounts were ultimately charged against the proceeds upon completion of the IPO.Fair Value of Financial Instruments. The carrying amount of cash and cash equivalents, accounts receivable, and accounts payableapproximates fair value due to their short-term maturities.Commitments and Contingencies. We record accruals for loss contingencies when we determine that it is probable that a liability has beenincurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts andcircumstances, forecasts of future events, and estimates of the financial impacts of such events.Revenue Recognition. We recognize revenue when all of the following criteria are met: (i) persuasive evidence of an exchangearrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price is fixed or determinable, and (iv) collectability isreasonably assured.We earn revenue from the natural gas gathering services that we provide to our natural gas producer customers. We recognize this revenueas gathering services and other fees revenue. We also earn revenue from the sale of physical natural gas retained from our customers andcondensate retained from gathering services. We sell the natural gas that we retain from our DFW Midstream customers to offset the powerexpenses of the electric-driven compression on the DFW Midstream system. We record these revenue sources as natural gas andcondensate sales revenue.Certain customers reimburse us for costs we incur as outlined in the related gas gathering contract. We record costs incurred and reimbursedby our customers on a gross basis.Our natural gas gathering agreements provide a monthly or annual minimum volume commitment ("MVC") from certain of our customers.Under these monthly or annual MVCs, our customers agree to ship a minimum volume of natural gas on our gathering systems or to pay aminimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to us at the end ofthe contract month or year, as applicable, if its actual throughput volumes are less than its MVC for that month or year. Certain customersare entitled to utilize shortfall payments to offset gathering fees in one or more subsequent periods to the extent that such customer'sthroughput volumes in subsequent periods exceed its MVC for that period. These contract provisions range from 12 months to nine years.We record customer billings for obligations under their MVCs as deferred revenue when the customer has the right to utilize shortfallpayments to offset gathering fees in subsequent periods. We recognize deferred revenue under these arrangements in revenue once allcontingencies or potential performance obligations associated with the related volumes have either (i) been satisfied through the gathering offuture excess volumes of natural gas, or (ii) expired (or lapsed) through the passage of time pursuant to the terms of the applicable naturalgas gathering agreement. We classify deferred revenue as short term for arrangements where the expiration of a customer's right to utilizeshortfall payments is twelve months or less. As of December 31, 2012, our customers have been billed $11.8 million of shortfall payments,of which $0.7 million was included in accounts receivable as of December 31, 2012, attributed to arrangements that provide the customer theability to offset gathering fees in the next one month to nine years to the extent that a customer's throughput volumes exceed its MVC.Unit-Based Compensation. For awards of unit-based compensation, we determine a grant date fair value and recognize the relatedcompensation expense, adjusted for expected forfeitures, in the statement of operations over the vesting period of the respective awards. SeeNote 9 for additional information.Income Taxes. We are not subject to federal and state income taxes, except as noted below, because we are structured as a partnership. Asa result, our unitholders or members are individually responsible for paying federal and state income taxes on their share of our taxableincome.In general, legal entities that are chartered, organized or conducting business in the state of Texas are subject to the Revised Texas FranchiseTax (the "Texas Margin Tax"). Although the bill states that the Texas Margin Tax is not an income tax, it has the characteristics of an incometax since it is determined by applying a tax rate to a tax base that considers both revenues and expenses. The tax rate is 1% for most taxableentities. The tax base is the taxable entity's margin. As outlined by statute, margin should equal the least of three calculations based oneligibility: (i) total revenue less cost of goods sold, (ii) total revenue less compensation and (iii) 70% of total revenue. TotalF-11Table of Contentsrevenue, costs of goods sold and compensation are all defined by statute. Our financial statements reflect provisions for these tax obligations.Earnings Per Unit ("EPU"). Earnings per limited partner unit data is presented only for the period since the closing of SMLP’s IPO onOctober 3, 2012. We determined EPU by dividing the net income that was attributed, in accordance with the net income and loss allocationprovisions of the partnership agreement, to the common and subordinated unitholders under the two-class method, after deducting thegeneral partner's 2% interest in net income and any incentive distributions paid to the general partner, by the weighted-average number ofcommon and subordinated units outstanding during the period from October 1, 2012 to December 31, 2012. Diluted earnings per limitedpartner unit reflects the potential dilution that could occur if securities or other agreements to issue common units, such as unit-basedcompensation, were exercised, settled or converted into common units. When it is determined that potential common units resulting from anaward subject to performance or market conditions should be included in the diluted earnings per limited partner unit calculation, the impactis reflected by applying the treasury stock method.EPU for periods ended prior to the IPO have not been presented because Summit Investments' members held membership interests andnot units.Comprehensive Income. Comprehensive income is the same as net income for each year in the three-year period ended December 31,2012.Environmental Matters. We are subject to various federal, state and local laws and regulations relating to the protection of the environment.Although we believe that we are in compliance with applicable environmental regulations, the risk of costs and liabilities are inherent inpipeline ownership and operation. We can provide no assurances that significant costs and liabilities will not be incurred by the Partnership.We are not aware of any material contingent liabilities that currently exist with respect to environmental matters.Recent Accounting Pronouncements. Accounting standard setters frequently issue new or revised accounting rules. We review newpronouncements to determine the impact, if any, on our consolidated financial statements. There are currently no recent pronouncementsthat have been issued that we believe will materially affect the consolidated financial statements.3. ACQUISITIONSGrand River Gathering. In September 2011, we entered into a purchase and sale agreement with Encana Oil & Gas (USA) Inc., asubsidiary of Encana Corporation ("Encana"), to acquire certain natural gas gathering pipeline, dehydration and compression assets in thePiceance Basin in western Colorado (the "Grand River Transaction"). These assets gather production from the Mamm Creek, Orchard, andSouth Parachute fields in the area around Rifle, Colorado under long-term contracts ranging from 10 years to 25 years. The weighted-averagelife of these contracts was 12.8 years upon acquisition. The acquired assets included approximately 260 miles of pipeline and approximately90,000 horsepower of compression facilities. In addition to the acquisition of Grand River Gathering, we have a contractual relationship withEncana related to the development of midstream infrastructure to support Encana’s emerging Mancos and Niobrara shale developments.The Grand River Transaction closed on October 27, 2011, with an effective date of October 1, 2011, and was funded through an equitycontribution of $410.0 million and an aggregate of $200.0 million in promissory notes from the Sponsors. We accounted for the Grand RiverTransaction under the acquisition method of accounting, whereby the total purchase price was allocated to Grand River Gathering'sidentifiable tangible and intangible assets acquired and liabilities assumed based on their fair values as of October 27, 2011. The intangibleassets that were acquired are composed of gas gathering agreement contract values and right-of-way easements. Their fair values weredetermined based upon assumptions related to future cash flows, discount rates, asset lives, and projected capital expenditures to completethe Grand River Gathering system.During the second quarter of 2012, we received the remaining information needed to value the acquired construction work in process and theintangible assets and then finalized its determination of the assets acquired and liabilities assumed of Grand River Gathering as well as itspurchase price. As a result, we retrospectively recorded an adjustment to decrease construction work in process by $4.7 million and decreaseintangible assets by $37.9 million. It also recognized deferred revenue related to minimum volume commitment payments received prior tothe acquisition of Grand River Gathering. These amounts can be used by the customer to offset gathering fees in one or more subsequentperiods to the extent that such customer’s throughput volumes in subsequent periods exceed its minimum volume commitment.Additionally, net working capital was recorded as other current liabilitiesF-12Table of Contentsand represents the final settlement of the remaining assets acquired and liabilities assumed. These adjustments to the preliminary purchaseprice and the allocation to the assets acquired and liabilities assumed resulted in the recognition of goodwill totaling $45.5 million.The final purchase price allocation has been recorded and presented on a retrospective basis. We believe that the goodwill recorded upon thefinalization of the allocation represents the incremental value of future cash flow potential attributed to estimated future gathering serviceswithin the emerging Mancos and Niobrara shale developments.The final fair values of the assets acquired and liabilities assumed as of October 27, 2011, were as follows: (In thousands)Purchase price assigned to Grand River Gathering $590,210Property, plant, and equipment$295,240 Gas gathering agreement contract intangibles244,100 Rights-of-way8,016 Total assets acquired547,356 Deferred revenue1,770 Other current liabilities854 Total liabilities assumed$2,624 Net identifiable assets acquired 544,732Goodwill $45,478Unaudited Pro Forma Financial Information. The following unaudited pro forma financial information assumes that the Grand RiverTransaction occurred on January 1, 2010. We recorded revenue of $12.8 million and net income of $2.1 million for the two-month periodfrom November 1, 2011 through December 31, 2011. The pro forma adjustments were derived by annualizing the actual operating results forGrand River Gathering that were recorded in 2011. Transaction costs have been adjusted to show their pro forma effect as though they hadbeen incurred in 2010 and not incurred in 2011. Year ended December 31, 2011 2010 (In thousands)Total revenue per statement of operations$103,552 $31,676Pro forma revenue adjustment64,119 76,943Pro forma total revenue$167,671 $108,619 Net income per statement of operations$37,951 $8,172Pro forma net income adjustment13,294 15,884Pro forma transaction costs incurred adjustment3,160 (3,160)Pro forma net income$54,405 $20,896The unaudited pro forma financial information presented above is not necessarily indicative of what our financial position or results ofoperations would have been if the Grand River Transaction had occurred on January 1, 2010, or what SMLP’s financial position or results ofoperations will be for any future periods.F-13Table of Contents4. PROPERTY, PLANT, AND EQUIPMENT, NETDetails on property, plant, and equipment, net were as follows: Useful lives (Inyears) December 31, 2012 2011 (Dollars in thousands)Gas gathering systems30 $427,449 $335,083Compressor stations and compression equipment30 237,618 165,600Construction in progressn/a 45,919 147,616Other4-15 4,524 2,071Total 715,510 650,370Less accumulated depreciation (33,517) (12,180)Property, plant, and equipment, net $681,993 $638,190Construction in progress is depreciated consistent with its applicable asset class once it is placed in service. Depreciation expense related toproperty, plant and equipment and capitalized interest were as follows: Year ended December 31, 2012 2011 2010 (In thousands)Depreciation expense$21,337 $8,595 $3,355Capitalized interest2,784 3,362 —5. IDENTIFIABLE INTANGIBLE ASSETS, NONCURRENT LIABILITY AND GOODWILLIdentifiable Intangible Assets and Noncurrent Liability. We accounted for the acquisitions of DFW Midstream and Grand RiverGathering under the acquisition method of accounting. In connection with these acquisitions, we recognized separately identifiable intangibleassets and a noncurrent liability. Identifiable intangible assets and the noncurrent liability, which are subject to amortization, were as follows: December 31, 2012 Useful lives(In years) Gross carryingamount Accumulatedamortization Net (Dollars in thousands)Favorable gas gathering contracts18.7 $24,195 $(4,237) $19,958Contract intangibles12.4 244,100 (14,504) 229,596Rights-of-way28.3 38,848 (2,862) 35,986Total amortizable intangible assets $307,143 $(21,603) $285,540 Unfavorable gas gathering contract10.0 $10,962 $(3,542) $7,420F-14Table of Contents December 31, 2011 Useful lives(In years) Gross carryingamount Accumulatedamortization Net (Dollars in thousands)Favorable gas gathering contracts18.7 $24,195 $(2,522) $21,673Contract intangibles12.4 244,100 (1,862) 242,238Rights-of-way28.3 34,343 (1,541) 32,802Total amortizable intangible assets $302,638 $(5,925) $296,713 Unfavorable gas gathering contract10.0 $10,962 $(2,018) $8,944We recognized amortization expense as follows: Year ended December 31, 2012 2011 2010 (In thousands)Amortization expense – favorable gas gathering contracts$1,715 $1,718 $764Amortization expense – contract intangibles12,642 1,862 —Amortization expense – rights-of-way1,321 908 519Amortization expense – unfavorable gas gathering contract(1,524) (1,410) (549)The estimated aggregate annual amortization of intangible assets and noncurrent liability expected to be recognized as of December 31, 2012for each of the five succeeding fiscal years follows. Assets Liabilities (In thousands)2013$19,384 $1,441201422,189 1,549201525,142 1,650201626,521 1,571201725,891 1,438Goodwill. We recognized goodwill of $45.5 million in connection with the Grand River Transaction and allocated it to the Grand RiverGathering reporting unit (see Note 3). In September 2012, we performed our annual goodwill impairment testing and determined that the fairvalue of the Grand River Gathering reporting unit exceeded its carrying value resulting in no goodwill impairment. Prior to the completion ofGrand River Transaction, we had no goodwill, and thus no goodwill impairments.6. REVOLVING CREDIT FACILITYIn May 2011, we closed a senior secured revolving credit facility with total commitments of $285.0 million. Upon closing the revolving creditfacility, we distributed $132.9 million to Energy Capital Partners.In May 2012, we closed on an amendment and restatement of the revolving credit facility, which expanded our borrowing capacity to $550.0million. Upon closing of the amendment and restatement (i) Summit Investments contributed its assets and membership interests in GrandRiver Gathering to Summit Holdings and (ii) Summit Holdings borrowed an additional $163.0 million under the revolving credit facility andutilized $160.0 million of the borrowings to partially repay the promissory notes payable to the Sponsors.In July 2012, we borrowed $50.0 million under the revolving credit facility and used $49.2 million of the proceeds to repay the balance of thepromissory notes payable to the Sponsors.In October 2012, we used $140.0 million of the IPO proceeds and $5.0 million of existing cash to pay down the revolving credit facility. Priorto the IPO, aggregate repayments from existing cash totaled $15.8 million. As of December 31, 2012, the outstanding balance of therevolving credit facility was $199.2 million.F-15Table of ContentsThe revolving credit facility is secured by the membership interests of Summit Holdings, DFW Midstream and Grand River Gathering andsubstantially all of Summit Holdings', DFW Midstream's and Grand River Gathering's assets. It is guaranteed by Summit Holdings'subsidiaries. It allows for revolving loans, letters of credit and swingline loans. The revolving credit facility matures in May 2016.Borrowings under the revolving credit facility bear interest at the London Interbank Offered Rate ("LIBOR") plus an applicable margin or abase rate, as defined in the credit agreement. At December 31, 2012, the applicable margin under LIBOR borrowings was 2.75%, theinterest rate was 2.98% and the unused portion of the revolving credit facility totaled $350.8 million (subject to a commitment fee of 0.50%).The revolving credit agreement contains affirmative and negative covenants customary for credit facilities of its size and nature that, amongother things, limit or restrict the ability to (i) incur additional debt; (ii) make investments; (iii) engage in certain mergers, consolidations,acquisitions or sales of assets; (iv) enter into swap agreements and power purchase agreements; (v) enter into leases that wouldcumulatively obligate payments in excess of $30.0 million over any 12-month period; and (vi) prohibits the payment of distributions bySummit Holdings if a default then exists or would result therefrom, and otherwise limits the amount of distributions Summit Holdings canmake. In addition, the revolving credit facility requires Summit Holdings to maintain a ratio of consolidated trailing 12-month earnings beforeinterest, income taxes, depreciation and amortization ("EBITDA") to net interest expense of not less than 2.5 to 1.0 (as defined in the creditagreement) and a ratio of total indebtedness to consolidated trailing 12-month EBITDA of not more than 5.0 to 1.0, or not more than 5.5 to 1.0for up to six months following certain acquisitions (as defined in the credit agreement). As of December 31, 2012, we were in compliancewith the covenants in the revolving credit facility. There were no defaults during the year ended December 31, 2012.The revolving credit facility’s carrying value on the consolidated balance sheet is its fair value due to its floating rate.7. PARTNERS' CAPITAL AND MEMBERSHIP INTERESTSPartners' CapitalSMLP was formed in May 2012. Prior to its IPO on October 3, 2012, SMLP had no outstanding common or subordinated units oroperations.The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders ofthe subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimumquarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units willnot accrue arrearages for unpaid quarterly distributions or quarterly distributions less than the minimum quarterly distribution. If we do notpay the minimum quarterly distribution on our common units, our common unitholders will not be entitled to receive such payments in thefuture except during the subordination period. To the extent we have available cash in any future quarter during the subordination period inexcess of the amount necessary to pay the minimum quarterly distribution to holders of our common units, we will use this excess availablecash to pay any distribution arrearages related to prior quarters before any cash distribution is made to holders of subordinated units. Whenthe subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and thereafter no common unitswill be entitled to arrearages.The subordination period will end on the first business day after we have earned and paid at least (1) $1.60 (the minimum quarterlydistribution on an annualized basis) on each outstanding common unit and subordinated unit and the corresponding distribution on thegeneral partner's 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2015 or(2) $2.40 (150.0% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and thecorresponding distributions on the general partner's 2.0% interest and the related distribution on the incentive distribution rights for the four-quarter period immediately preceding that date, in each case provided there are no arrearages on the common units at that time.F-16Table of ContentsA reconciliation of the number of common limited partner, subordinated limited partner and general partner units from the IPO to December31, 2012 follows. Common Subordinated General partnerUnits, beginning of period— — —Units issued to the public in connection with the IPO14,380,000 — —Units issued to Summit Investments in connection with the IPO10,029,850 24,409,850 996,320Units issued to board of directors members2,577 — —Units, end of period24,412,427 24,409,850 996,320Beginning with the quarter ended December 31, 2012, our partnership agreement requires that we distribute all of our available cash (asdefined below) within 45 days after the end of each quarter, to unitholders of record on the applicable record date. On January 25, 2013, theboard of directors of our general partner declared a distribution of $0.41 per unit for the quarterly period ended December 31, 2012. Thedistribution, which totaled $20.4 million, was paid on February 14, 2013 to unitholders of record at the close of business on February 7,2013. There were no cash distributions paid by SMLP prior to 2013 other than the distribution of proceeds from the IPO.Cash Distribution PolicyOur partnership agreement requires that we distribute all of our available cash quarterly. Our policy is to distribute to our unitholders anamount of cash each quarter that is equal to or greater than the minimum quarterly distribution stated in our partnership agreement.Minimum Quarterly Distribution. Our partnership agreement generally requires that we make a minimum quarterly distribution to theholders of our common units and subordinated units of $0.40 per unit, or $1.60 on an annualized basis, to the extent we have sufficient cashfrom our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expensesto our general partner. The amount of distributions paid under our policy and the decision to make any distribution is determined by ourgeneral partner, taking into consideration the terms of our partnership agreement.Definition of Available Cash. Available cash generally means, for any quarter, all cash on hand at the end of that quarter:•less the amount of cash reserves established by our general partner at the date of determination of available cash for that quarter to:•provide for the proper conduct of our business (including reserves for our future capital expenditures and anticipated future debtservice requirements);•comply with applicable law, any of our debt instruments or other agreements; or•provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (providedthat our general partner may not establish cash reserves for distributions unless it determines that the establishment of reserveswill not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages onsuch common units for the current quarter);•plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for thequarter resulting from working capital borrowings made subsequent to the end of such quarter.General Partner Interest and Incentive Distribution Rights. Our general partner is entitled to 2.0% of all distributions that we makeprior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us tomaintain its current general partner interest. Our general partner's initial 2.0% interest in our distributions will be reduced if we issueadditional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% generalpartner interest.Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentage allocations, up to amaximum of 50.0% (as set forth in the chart below), of the cash we distribute from operating surplus in excess of $0.46 per unit per quarter.The maximum distribution of 50.0% includes distributions paid to our general partner on its 2.0% general partner interest and assumes thatour general partner maintains its generalF-17Table of Contentspartner interest at 2.0%. The maximum distribution of 50.0% does not include any distributions that our general partner may receive on anycommon or subordinated units that it owns.Percentage Allocations of Available Cash. The following table illustrates the percentage allocations of available cash between theunitholders and our general partner based on the specified target distribution levels. The amounts set forth in the column MarginalPercentage Interest in Distributions are the percentage interests of our general partner and the unitholders in any available cash we distributeup to and including the corresponding amount in the column Total Quarterly Distribution Per Unit Target Amount. The percentage interestsshown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distributionamounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its2.0% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2.0%general partner interest, our general partner has not transferred its incentive distribution rights and that there are no arrearages on commonunits. Total quarterly distribution per unittarget amount Marginal percentage interest in distributions Unitholders General partnerMinimum quarterly distribution$0.40 98.0% 2.0%First target distribution$0.40 up to $0.46 98.0% 2.0%Second target distributionabove $0.46 up to $0.50 85.0% 15.0%Third target distributionabove $0.50 up to $0.60 75.0% 25.0%Thereafterabove $0.60 50.0% 50.0%Membership InterestsEnergy Capital Partners and GE Energy Financial Services hold membership interests in Summit Investments. Such membershipinterests gives them the right to participate in distributions and to exercise the other rights or privileges available to each entity under SummitInvestments' Amended and Restated Limited Liability Operating Agreement (the "Summit LLC Agreement"). In addition, certain membersof Summit Investments’ management hold ownership interests in the form of Class B membership interests (the "SMP Net ProfitsInterests") through their ownership in Summit Midstream Management, LLC.In accordance with the Summit LLC Agreement, capital accounts are maintained for Summit Investments’ members. The capital accountprovisions of the Summit LLC Agreement incorporate principles established for U.S. federal income tax purposes and as such are notcomparable to the equity accounts reflected under GAAP in our consolidated financial statements.The Summit LLC Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that itsmembership interest holders will receive. Capital contributions required under the Summit LLC Agreement are in proportion to themembers' respective percentage ownership interests. The Summit LLC Agreement also contains provisions for the allocation of net earningsand losses to members. For purposes of maintaining partner capital accounts, the Summit LLC Agreement specifies that items of incomeand loss shall be allocated among the partners in accordance with their respective percentage interests described above.Noncontrolling Interest in DFW Midstream. We hold all of the Class A membership interests of DFW Midstream. As the sole Class AMember, we hold units that represent membership interests, which give the holders thereof the right to participate in distributions and toexercise the other rights or privileges available to them under the DFW Midstream Amended and Restated Limited Liability CompanyAgreement and Contribution Agreement (collectively the "LLC Agreement"). The capital account provisions of the LLC Agreementincorporated principles established for U.S. federal income tax purposes and as such are not comparable to the equity accounts reflectedunder GAAP in our consolidated financial statements.In accordance with the LLC Agreement, capital accounts are maintained for the members. Additionally, the LLC Agreement sets forth thecalculation to be used in determining the amount and priority of cash distributions that Class A Members receive.During the year ended December 31, 2010, we had several changes in membership interests related to the ownership of DFW Midstream.In June 2010, we entered into a Membership Interest Purchase Agreement with Texas Competitive Electric Holdings Company LLC("TCEH") whereby we purchased all of TCEH's membership interests in DFW Midstream for cash consideration of $90.7 million. Amountsreported as noncontrolling interest in 2010 relate to TCEH's ownership interests in DFW Midstream prior to the purchase. The change in ourownershipF-18Table of Contentsinterest in DFW Midstream as a result of the purchase decreased our membership interests by $25.1 million in 2010, as the cashconsideration paid exceeded the carrying value of the noncontrolling interest at the date of purchase.Prior to our purchase of TCEH's interest in DFW Midstream in June 2010, we held a 75% Class A membership interest and TCEH held a25% Class A membership interest. However, distributions and allocations of income and loss were based on a sharing percentage as definedin the LLC Agreement resulting in an allocation or distribution on a basis of 70.5% for the Predecessor and 29.5% for TCEH. Capitalcontributions required under the LLC Agreement were made in proportion to the owners' respective percentage ownership interests. In 2010,Energy Capital Partners made cash contributions of $194.1 million to the Company that were primarily used to fund ongoing capitalexpenditures of DFW Midstream and purchase TCEH's noncontrolling interest. TCEH funded capital contributions of $10.7 million in 2010.8. EARNINGS PER UNITThe following table presents details on EPU. Year endedDecember 31, 2012 (Dollars in thousands,except per-unit amounts)Net income attributable to the post-IPO period$17,614Less: net income attributable to general partner352Net income attributable to limited partners$17,262 Net income attributable to common units$8,632 Weighted-average common units outstanding – basic24,412,427Earnings per common unit – basic$0.35 Weighted-average common units outstanding – diluted24,543,985Earnings per common unit – diluted$0.35 Net income attributable to subordinated units$8,630 Weighted-average subordinated units outstanding – basic and diluted24,409,850Earnings per subordinated unit – basic and diluted$0.35The weighted-average number of units used to calculate diluted earnings per common limited partner unit includes the effect of 125,000phantom units granted in connection with the IPO and 6,558 restricted unit awards granted in connection with the exchange of certain netprofits interests awards related to DFW Midstream (see Note 9).9. UNIT-BASED COMPENSATIONLong-Term Incentive Plan. The 2012 Long-Term Incentive Plan (the "LTIP") provides for equity awards to eligible officers, employees,consultants and directors of our general partner and its affiliates, thereby linking the recipients' compensation directly to SMLP’sperformance. The LTIP is administered by our general partner's board of directors, though such administration function may be delegated to acommittee appointed by the board. A total of 5,000,000 common units was reserved for issuance pursuant to and in accordance with the LTIP.The LTIP provides for the granting, from time to time, of unit-based awards, including common units, restricted units, phantom units, unitoptions, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. Grants are made at thediscretion of the board of directors or compensation committee of our general partner. The administrator of the LTIP may make grants underthe LTIP that contain such terms, consistent with the LTIP, as the administrator may determine are appropriate, including vesting conditions.The administrator of the LTIP may, in its discretion, base vesting on the grantee's completion of a period of service or upon theF-19Table of Contentsachievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described inan award agreement. Termination of employment prior to vesting will result in forfeiture of the awards, except in limited circumstances asdescribed in the plan documents. Units that are canceled or forfeited will be available for delivery pursuant to other awards.In connection with the IPO and pursuant to the LTIP, the board of directors of our general partner granted 125,000 phantom units withdistribution equivalent rights to certain key employees that provide services for us. A phantom unit is a notional unit that entitles the granteeto receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in thediscretion of the administrator, cash equal to the fair market value of a common unit. Distribution equivalent rights for each phantom unitprovide for a lump sum cash amount equal to the accrued distributions from the grant date to be paid in cash upon the vesting date. Thephantom units granted in connection with the IPO vest on the third anniversary of the consummation of the IPO. Upon vesting, awards maybe settled in cash and/or common units, at the discretion of the board of directors.The grant date fair value of the phantom unit awards, based on a per-unit fair value of $20.00, was $2.5 million. Compensation expenserecognized in 2012 was approximately $0.2 million. The following table presents phantom unit activity for the year ended December 31,2012: Year ended December 31, 2012Nonvested phantom units, beginning of period —Phantom units granted 125,000Phantom units vested —Phantom units forfeited —Nonvested phantom units, end of period 125,000Upon vesting, management intends to settle the phantom unit awards with units. As of December 31, 2012, the unrecognized non-cashcompensation expense related to the phantom units was $2.3 million. Incremental non-cash compensation expense will be recorded overthe remaining vesting period of 2.8 years. No forfeitures were assumed in the determination of estimated compensation expense due to alack of history.DFW Net Profits Interests. In connection with the formation of DFW Midstream in 2009, up to 5% of DFW Midstream's total membershipinterests were authorized for issuance as Class B membership interests (the "DFW Net Profits Interests"). DFW Net Profits Interestsparticipate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vestedDFW Net Profits Interests. The DFW Net Profits Interests are accounted for as compensatory awards. Additional DFW Net Profits Interestswere granted on April 1, 2010 and July 28, 2010. All grants vest ratably over four years and provide for accelerated vesting in certain limitedcircumstances, including a qualifying termination following a change in control (as defined in the underlying award agreement and LLCAgreement). As of December 31, 2012, 4.80% of DFW Net Profits Interests had been granted to certain members of management and0.47% DFW Net Profits Interests had been forfeited.During the year ended December 31, 2011, we determined the fair value of the DFW Net Profits Interests as of the respective grant dates forthe grants made prior to that date with assistance from a third-party valuation expert. Therefore, the 2009 and 2010 awards were valuedretrospectively. The DFW Net Profits Interests were valued utilizing an option pricing method, which models the Class A and Class Bmembership interests as call options on the underlying equity value of DFW Midstream and considers the rights and preferences of eachclass of equity in order to allocate a fair value to each class.A significant input of the option pricing method is the enterprise value of DFW Midstream. We estimated the enterprise value utilizing acombination of the income and market approaches. The income approach utilized the discounted cash flow method, whereby we applied adiscount rate to estimated future cash flows of DFW Midstream. Key inputs include forecasted gathering volumes, revenues and costs;unlevered equity betas of the DFW Midstream peer group; equity market risk premium; company-specific risk premium; and terminal growthrate. Under the market approach, trading multiples of the securities of publicly-traded peer companies were applied to DFW Midstream'sestimated future cash flows.Additional significant inputs used in the option pricing method include the length of holding period, discount for lack of marketability andvolatility. We determined the length of holding period primarily based on our Sponsors' expectations as of the grant date. We estimated thediscount for lack of marketability and volatility with assistance from a third-party valuation firm. We estimated the discount for lack ofmarketability using a protective putF-20Table of Contentsmethodology. The protective put methodology consisted of estimating the cost to insure an investment in the DFW Net Profits Interests overthe length of the holding period. Using the Black-Scholes option pricing model, we calculated the cost of a put option for the DFW Net ProfitsInterests as of the various grant dates. The discount for lack of marketability, in each case, is equal to the put option value divided by the valueof the underlying membership interest. We estimated the expected volatility of the DFW Net Profits Interests based on the historical andimplied volatilities of the securities of publicly-traded peer companies. We estimated historical volatility based on daily stock price returns overa look-back period commensurate with the length of the holding period for each grant date of DFW Net Profits Interests. We estimated impliedvolatility based on the average implied volatility of the publicly-traded peer companies using data from Standard & Poor's Capital IQproprietary research tool. We based the expected volatility conclusions on consideration of both the historical and implied volatilities of thepublicly-traded peer companies as of the various grant dates. The inputs we used in the option pricing method for the DFW Net ProfitsInterests by grant date were as follows: July2010grant April2010grant September2009grantLength of holding period restriction (In years)3.43 3.75 4.25Discount for lack of marketability35.9% 30.9% 34.8%Volatility53.7% 49.8% 52.5%Information regarding the amount and grant date fair value of the vested and nonvested DFW Net Profits Interests were as follows: Year ended December 31, 2012 2011 2010 PercentageInterest Weighted-averagegrant date fairvalue (per 1.0% ofDFW Net ProfitsInterest) PercentageInterest Weighted-averagegrant date fairvalue (per 1.0% ofDFW Net ProfitsInterest) PercentageInterest Weighted-averagegrant date fairvalue (per 1.0% ofDFW Net ProfitsInterest) (Dollars in thousands)Nonvested, beginning of period1.750% $306 2.850% $295 4.125% $220Granted0.000% $— 0.000% $— 0.300% $1,060Vested1.644% $256 1.100% $277 1.175% $252Forfeited0.069% $765 0.400% $220 0.400% $220Nonvested, end of period0.038% $1,650 1.750% $306 2.850% $295Vested, end of period4.294% $257 2.650% $258 1.550% $245We recognize non-cash compensation expense ratably over the four-year vesting period. Non-cash compensation expense, related to theDFW Net Profits Interests, recognized within general and administrative expense was as follows: Year ended December 31, 2012 2011 2010 (In thousands)Non-cash compensation expense $688 $2,171 $—As of December 31, 2012, the unrecognized non-cash compensation expense related to the DFW Net Profits Interests was $0.1 million.Incremental non-cash compensation expense will be recorded over the remaining expected weighted-average vesting period of 1.3 years.For the year ended December 31, 2011, non-cash compensation expense also included approximately $0.6 million of expense related to2010 and 2009. During the year ended December 31, 2011, the Predecessor modified the awards to remove a rate of return payout hurdle.As a result of the modification, we valued the Class B Units immediately prior to and following the modification to determine incrementalcompensation expense. TheF-21Table of Contentsmodification resulted in the immediate recognition of $1.4 million of expense attributed to the previously vested Class B Units. This amountwas included in compensation expense for the year ended December 31, 2011.In October 2012, we entered into exchange agreements with two employee holders of DFW Net Profits Interests whereby we exchangedcash for their vested DFW Net Profits Interests and SMLP restricted units for their unvested DFW Net Profits Interests. Such transactionswere not material.SMP Net Profits Interests. In connection with the formation of Summit Investments in 2009, up to 7.5% of total membership interestswere authorized for issuance. SMP Net Profits Interests participate in distributions upon time vesting and the achievement of certaindistribution targets to Class A members or higher priority vested SMP Net Profits Interests. The SMP Net Profits Interests are accounted foras compensatory awards. Additional SMP Net Profits Interests were granted in April 2010, April 2011, October 2011 and January 2012. Allgrants vest ratably over five years and provide for accelerated vesting in certain limited circumstances, including a qualifying terminationfollowing a change in control (as defined in the underlying award agreement and Summit LLC Agreement). As of December 31, 2012,6.355% of SMP Net Profits Interests had been granted to certain members of management, and no SMP Net Profits Interests had beenforfeited.We determined the fair value of the SMP Net Profits Interests as of the respective grant dates with assistance from a third-party valuationexpert. The 2012 and 2011 awards were valued contemporaneously within the year issued, and the 2009 and 2010 awards were valuedretrospectively in 2011. We valued the SMP Net Profits Interests utilizing an option pricing method, which models the Class A and Class Bmembership interests as call options on the underlying equity value of Summit Investments and considers the rights and preferences ofeach class of equity in order to allocate a fair value to each class.A significant input of the option pricing method is the enterprise value of Summit Investments. We estimated enterprise value utilizing acombination of the income and market approaches. The income approach utilized the discounted cash flow method, whereby we applied adiscount rate to estimated future cash flows of Summit Investments. Key inputs include forecasted gathering volumes; revenues and costs;unlevered equity betas of Summit Investments' peer group; equity market risk premium; company-specific risk premium; and terminalgrowth rate. Under the market approach, we applied trading multiples of the securities of publicly-traded peer companies to SummitInvestments' estimated future cash flows.Additional significant inputs used in the option pricing method include length of holding period, discount for lack of marketability and volatility.The length of holding period was primarily determined based upon our Sponsors' expectations as of the grant date. We estimated thediscount for lack of marketability and volatility with assistance from a third-party valuation firm. We estimated the discount for lack ofmarketability using a protective put methodology. The protective put methodology consisted of estimating the cost to insure an investment inthe SMP Net Profits Interests over the length of the holding period. Using the Black-Scholes option pricing model, we calculated the cost of aput option for the SMP Net Profits Interests as of the various grant dates. The discount for lack of marketability, in each case, is equal to theput option value divided by the value of the underlying membership interest. We estimated the expected volatility of the SMP Net ProfitsInterests based on the historical and implied volatilities of the securities of publicly-traded peer companies. We estimated historical volatilitybased on daily stock price returns over a look-back period commensurate with the length of the holding period for each grant of SMP NetProfits Interests. We estimated implied volatility based on the average implied volatility of the publicly-traded peer companies using data fromStandard & Poor's Capital IQ proprietary research tool. We based the expected volatility conclusions on consideration of both the historical andimplied volatilities of the publicly-traded peer companies as of the various grant dates.The inputs used in the option pricing method for the SMP Net Profits Interests by grant date were as follows: January2012grant October2011grant April2011grant April2010 grant September 2009 grantLength of holding period restriction (In years)2.93 3.21 4.75 3.75 4.25Discount for lack of marketability24.0% 33.1% 29.6% 30.9% 34.8%Volatility37.0% 49.3% 43.2% 49.8% 52.5%F-22Table of ContentsInformation regarding the amount and grant-date fair value of the vested and nonvested SMP Net Profits Interests was as follows: Year ended December 31, 2012 2011 2010 PercentageInterest Weighted-average grantdate fair value(per 1.0% ofSMP Net ProfitsInterest) PercentageInterest Weighted-average grantdate fair value(per 1.0% ofSMP Net ProfitsInterest) PercentageInterest Weighted-average grantdate fair value(per 1.0% ofSMP Net ProfitsInterest) (Dollars in thousands)Nonvested, beginning of period3.958% $1,003 2.944% $601 2.660% $386Granted0.500% $1,780 2.000% $1,505 1.005% $1,125Vested1.271% $965 0.986% $818 0.721% $541Nonvested, end of period3.187% $1,140 3.958% $1,003 2.944% $601Vested, end of period3.168% $788 1.897% $669 0.911% $508We recognize non-cash compensation expense ratably over the five-year vesting period. Non-cash compensation expense, related to the SMPNet Profits Interests, recognized in general and administrative expense was as follows: Year ended December 31, 2012 2011 2010 (In thousands)Non-cash compensation expense $919 $1,269 $—As of December 31, 2012, the unrecognized non-cash compensation expense related to the SMP Net Profits Interests was $3.1 million.Incremental non-cash compensation expense will be recorded by Summit Investments over the remaining expected weighted-averagevesting period of 3.9 years. For the year ended December 31, 2011, non-cash compensation expense also included approximately $0.5million of expense related to 2010 and 2009.10. BENEFIT PLANWe established a defined contribution benefit plan for our employees in 2009. The expense associated with this plan was approximately $0.2million in 2012, $0.1 million in 2011, and $0.1 million in 2010.11. COMMITMENTS AND CONTINGENCIESOperating Leases. We lease various office space to support our operations and have determined that our leases are operating leases. Totalrent expense related to operating leases, which is recognized in general and administrative expenses, was as follows: Year ended December 31, 2012 2011 2010 (In thousands)Total rent expense$724 $489 $212F-23Table of ContentsThe schedule of future minimum lease payments for operating leases that had initial or remaining noncancelable lease terms in excess ofone year as of December 31, 2012 was as follows: Operating leases (In thousands)2013$8592014787201566220166302017217Legal Proceedings. Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normalcourse of business, except as described below, 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 variousenvironmental protection statutes to which we are subject.On August 21, 2012, four former DFW Midstream employees (the "Plaintiffs") who, by virtue of their Class B membership in DFWMidstream Management LLC ("DFW Management"), collectively own an aggregate 4.1% vested net profits interests in DFW Midstream,filed a claim in the Court of Chancery of the State of Delaware against Summit Investments, Summit Holdings, DFW Midstream and DFWManagement (collectively, the "Defendants") seeking dissolution and wind-up of DFW Midstream and DFW Management or, in thealternative, a repurchase of the Plaintiffs' net profits interests. The Plaintiffs also seek other unspecified monetary damages, includingattorneys' fees and costs. The complaint alleges that the Defendants breached (i) the DFW Midstream limited liability company agreement;(ii) compensatory arrangements with each Plaintiff; (iii) the implied covenant of good faith and fair dealing; and (iv) in the case of SummitInvestments and Summit Holdings, their alleged fiduciary duties to the Plaintiffs. The complaint further alleges that the Defendants actedfraudulently with respect to the Plaintiffs. On September 28, 2012, the Defendants filed a motion to dismiss all of Plaintiffs’ claims in thismatter. The court heard oral arguments on the motion to dismiss on December 12, 2012, and a decision on the motion is expected in thefirst half of 2013. The court has stayed discovery pending its resolution of Defendants’ motion to dismiss.While we are unable to predict the outcome of this litigation, we believe that the Plaintiffs' allegations are meritless. We intend to vigorouslydefend ourselves against these allegations, and we do not believe that the dispute, even if determined adversely against us, would have amaterial effect on our financial position, results of operations or cash flows.12. RELATED-PARTY TRANSACTIONSGeneral and Administrative Expense Allocation. Our general partner and its affiliates do not receive any management fee or othercompensation in connection with the management of our business, but will be reimbursed for expenses incurred on our behalf. Under ourpartnership agreement, we reimburse our general partner and its affiliates for certain expenses incurred on our behalf, including, withoutlimitation, salary, bonus, incentive compensation and other amounts paid to our general partner's employees and executive officers whoperform services necessary to run our business. In addition, we reimburse our general partner for compensation, travel and entertainmentexpenses for the directors serving on the board of directors of our general partner and the cost of director and officer liability insurance. Ourpartnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. Amounts paid toreimburse the general partner for these expenses were approximately $1.2 million in 2012. As of December 31, 2012, we had a $0.8 millionreceivable from our general partner for expenses that we paid that were not allocated to the Partnership.F-24Table of ContentsElectricity Management Services Agreement. We entered into a consulting arrangement with Equipower Resources Corp., wherebythey assist DFW Midstream with managing its electricity price risk. Equipower Resources Corp. is an affiliate of our Sponsor, Energy CapitalPartners. Amounts paid for such services were as follows: Year ended December 31, 2012 2011 2010 (In thousands)Payments for electricity management consulting services$204 $11 $—Promissory Notes Payable to Sponsors. In conjunction with the Grand River Transaction, we executed $200.0 million of promissorynotes, on an unsecured basis, with the Sponsors. The notes had an 8% interest rate and were scheduled to mature in October 2013. In May2012, we borrowed $163.0 million under the revolving credit facility and used a portion of the same borrowings to prepay $160.0 millionprincipal amount of the promissory notes payable to the Sponsors. Then in July 2012, we borrowed an additional $50.0 million under therevolving credit facility, a portion of which was used to pay the remaining $49.2 million principal amount of the promissory notes payable toSponsors (inclusive of accrued pay-in-kind interest).In accordance with the terms of the underlying note agreement, prior to their repayment in July 2012, we elected to make all interestpayments on the note in kind. The amount of interest paid in kind and accrued to the balance of the notes for year ended December 31, 2012,was approximately $6.3 million, of which we capitalized $0.9 million of interest expense related to costs incurred on capital projects underconstruction.Diligence Expenses. In the past, the Sponsors reimbursed Summit Investments for transactional due diligence expenses related toproposed transactions that were not completed. As of December 31, 2011, we had a receivable from the Sponsors of $1.3 million for similarexpenses. During the year ended December 31, 2012, we were reimbursed $0.3 million, while $1.0 million was not paid.Transition Services Agreement. We executed a transition services agreement with TCEH (an affiliate until June 2010) in September2009. The services provided under the transition services agreement included our use of: (i) office space and computers; (ii) accounting andfinancial reporting services support; (iii) general support for certain health benefit matters; (iv) certain information technology support; (v) right-of-way services; and (vi) public relation services. The costs and rates charged for each service were negotiated and mutually agreed to by bothparties. The termination date for each service varied and included an option to extend certain services. Year ended December 31, 2012 2011 2010 (In thousands)Transition services agreement expenses$— $39 $13713. CONCENTRATIONS OF RISKFinancial instruments that potentially subject us to concentrations of credit risk consist of cash and accounts receivable. We maintain ourcash in bank deposit accounts that, at times, may exceed federally insured limits. We have not experienced any losses in such accounts anddo not believe we are exposed to any significant risk.Accounts receivable are primarily from natural gas producers shipping natural gas and from natural gas marketers' purchase and sale ofnatural gas. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in thatour customers may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of ourcounterparties and generally require letters of credit for receivables from customers that are judged to have sub-standard credit, unless thecredit risk can otherwise be mitigated.F-25Table of ContentsCustomers accounting for more than 10% of total revenues were as follows: Year ended December 31, 2012 2011 2010Revenue: Customer A20% 34% 50%Customer B* 10% 11%Customer C12% 17% 20%Customer D* 12% *Customer E28% * *__________* Customer did not exceed 10%.Customers accounting for more than 10% of total accounts receivable were as follows: December 31, 2012 2011Accounts receivable: Customer A24% 43%Customer B* *Customer C* *Customer D* *Customer E38% 16%__________* Customer did not exceed 10%.14. UNAUDITED QUARTERLY FINANCIAL DATASummarized information on the consolidated results of operations for each of the quarters during the two-year period ended December 31,2012, follows. Quarter endedDecember 31, 2012 Quarter endedSeptember 30, 2012 Quarter endedJune 30, 2012 Quarter endedMarch 31, 2012 (In thousands, except per-unit amounts)Total revenues$48,634 $40,975 $40,107 $35,783 Net income$17,614 $7,396 $9,129 $7,587Less: net income attributable to general partner352 Net income attributable to limited partners$17,262 Earnings per common unit – basic$0.35 Earnings per common unit – diluted$0.35 Earnings per subordinated unit – basic and diluted$0.35 F-26Table of Contents Quarter endedDecember 31, 2011 Quarter endedSeptember 30, 2011 Quarter endedJune 30, 2011 Quarter endedMarch 31, 2011 (In thousands)Total revenues$39,524 $22,160 $22,693 $19,175 Net income$10,205 $9,807 $10,428 $7,511Quarterly amounts may not add to the corresponding annual amounts due to rounding.F-27EXHIBIT 10.12FINAL—EXECUTION COPYAmended and Restated Employment Agreement This Amended and Restated Employment Agreement (the “Agreement”), entered into on March 8, 2012 (the “EffectiveDate”), is made by and between Brad N. Graves (the “Executive”) and Summit Midstream Partners, LLC, a Delaware limited liabilitycompany (together with any of its subsidiaries and affiliates as may employ the Executive from time to time, and any successor(s)thereto, the “Company”).RECITALSA.The Company and the Executive are parties to an employment agreement, dated April 1, 2010 (the “OriginalEmployment Agreement”).B.The Company and the Executive desire to amend and restate the Original Employment Agreement in theform hereof.C.The Company desires to assure itself of the continued services of the Executive by engaging the Executiveto perform services under the terms hereof.D.The Executive desires to continue to provide services to the Company on the terms herein provided.AGREEMENTNOW, THEREFORE, in consideration of the foregoing and of the respective covenants and agreements set forth belowthe parties hereto agree as follows:1.Certain Definitions.(a)“AAA” shall have the meaning set forth in Section 19.(b)“Affiliate” shall mean, with respect to any Person, any other Person directly or indirectly controlling, controlled by,or under common control with, such Person where “control” shall have the meaning given such term underRule 405 of the Securities Act of 1933, as amended from time to time.(c)“Agreement” shall have the meaning set forth in the preamble hereto.(d)“Annual Base Salary” shall have the meaning set forth in Section 3(a).(e)“Annual Bonus” shall have the meaning set forth in Section 3(b).(f)“Board” shall mean the Board of Managers of the Company or any successor governing body.EXH 10.12-1(g)The Company shall have “Cause” to terminate the Executive’s employment hereunder upon: (i) the Executive’swillful failure to substantially perform the duties set forth herein (other than any such failure resulting fromthe Executive’s Disability); (ii) the Executive’s willful failure to carry out, or comply with, in any materialrespect any lawful directive of the Board; (iii) the Executive’s commission at any time of any act or omissionthat results in, or may reasonably be expected to result in, a conviction, plea of no contest, plea of nolocontendere, or imposition of unadjudicated probation for any felony or crime involving moral turpitude; (iv)the Executive’s unlawful use (including being under the influence) or possession of illegal drugs on theCompany’s premises or while performing the Executive’s duties and responsibilities hereunder; (v) theExecutive’s commission at any time of any act of fraud, embezzlement, misappropriation, materialmisconduct, conversion of assets of the Company, or breach of fiduciary duty against the Company (or anypredecessor thereto or successor thereof); or (vi) the Executive’s material breach of this Agreement, theSMM LLC Agreement or other agreements with the Company (including, without limitation, any breach ofthe restrictive covenants of any such agreement); and which, in the case of clauses (i), (ii) and (vi), continuesbeyond thirty (30) days after the Company has provided the Executive written notice of such failure orbreach (to the extent that, in the reasonable judgment of the Board, such failure or breach can be cured bythe Executive).(h)“Change in Control” shall, prior to a Public Offering, have the meaning set forth in the award agreement betweenthe Executive, Summit Midstream Management LLC, and the Company, dated March 1, 2010, granting anaward of downstairs profits interests to Summit Midstream Management, LLC and an award of upstairsprofits interests to the Executive, and, after a Public Offering, mean: (i) any “person” or “group” within themeaning of Sections 13(d) and 14(d)(2) of the Exchange Act, other than the Company, Energy CapitalPartners II, LP or any of their respective Affiliates (as determined immediately prior to such event), shallbecome the beneficial owners, by way of merger, acquisition, consolidation, recapitalization, reorganization orotherwise, of fifty percent (50%) or more of the combined voting power of the equity interests in theGeneral Partner or the Partnership; (ii) the limited partners of the Partnership approve, in one or a series oftransactions, a plan of complete liquidation of the Partnership, (iii) the sale or other disposition by the GeneralPartner or the Partnership of all or substantially all of its assets in one or more transactions to any Personother than the Company, the General Partner, the Partnership, Energy Capital Partners II, LP or any of theirrespective Affiliates; or (iv) a transaction resulting in a Person other than the Company, the General Partner,Energy Capital Partners II, LP or any of their respective Affiliates (as determined immediately prior to suchevent) being the sole general partner of the Partnership. EXH 10.12-2Execution Copy(i)“Code” shall mean the Internal Revenue Code of 1986, as amended.(j)“Company” shall, except as otherwise provided in Section 7(j), have the meaning set forth in the preamble hereto.(k)“Compensation Committee” shall mean the Compensation Committee of the Board, or if no such committee exists,the Board.(l)“Date of Termination” shall mean (i) if the Executive’s employment is terminated due to the Executive’s death, thedate of the Executive’s death; (ii) if the Executive’s employment is terminated due to the Executive’sDisability, the date determined pursuant to Section 4(a)(ii); (iii) if the Executive’s employment is terminatedpursuant to Section 4(a)(iii)-(vi) either the date indicated in the Notice of Termination or the date specified bythe Company pursuant to Section 4(b), whichever is earlier; or (iv) if the Executive’s employment isterminated pursuant to Section 4(a)(vii)-(viii), the date immediately following the expiration of the then-current Term.(m)“Disability” shall mean the Executive’s inability to engage in any substantial gainful activity by reason of anymedically determinable physical or mental impairment that can be expected to result in death or that can beexpected to last for a continuous period of not less than twelve (12) months as determined by a physicianjointly selected by the Company and the Executive.(n)“Effective Date” shall have the meaning set forth in the preamble hereto.(o)“Exchange Act” shall mean the Securities Exchange Act of 1934, as amended.(p)“Excise Tax” shall have the meaning set forth in Section 6(b).(q)“Executive” shall have the meaning set forth in the preamble hereto.(r)“Extension Term” shall have the meaning set forth in Section 2(b).(s)“First Payment Date” shall have the meaning set forth in Section 5(b)(ii).(t)“General Partner” means Summit Midstream GP, LLC, a Delaware limited liability company.(u)The Executive shall have “Good Reason” to terminate the Executive’s employment hereunder within two (2) yearsafter the occurrence of one or more of the following conditions without the Executive’s written consent: (i)a material diminution in the Executive’s authority, duties, or responsibilities, as described herein; (ii) amaterial diminution in the Executive’s Annual Base Salary, target Annual Bonus (as a percentage of EXH 10.12-3Execution CopyAnnual Base Salary) or Annual Bonus range (as a percentage of Annual Base Salary), in each case as describedherein; (iii) a material change in the geographic location at which the Executive must perform the Executive’sservices hereunder that requires the Executive to relocate his residence to a location more than fifty (50) milesfrom Houston, Texas,; or (iv) any other action or inaction that constitutes a material breach of this Agreementby the Company; and which, in the case of any of the foregoing, continues beyond thirty (30) days after theExecutive has provided the Company written notice that the Executive believes in good faith that suchcondition giving rise to such claim of Good Reason has occurred, so long as such notice is provided within ninety(90) days after the initial existence of such condition.(v)“Initial Term” shall have the meaning set forth in Section 2(b).(w)“Installment Payments” shall have the meaning set forth in Section 5(b)(ii).(x)“LTIP” shall mean any long-term incentive plan adopted by the Company in connection with a Public Offering andidentified by the Company, in the adopting resolution or otherwise, as an “LTIP” pursuant hereto.(y)“Noncompete Option” shall mean the Company’s option, in its sole discretion, in the event of a termination ofemployment pursuant to Section 4(a)(vii) (Non-Extension of Term by the Company) or Section 4(a)(viii)(Non-Extension of Term by the Executive), to extend the Restricted Period through a date on or prior to thefirst (1st) anniversary of the Date of Termination, upon advance written notice to the Executive not lessthan thirty (30) days prior to the end of the then-current Term.(z)“Notice of Termination” shall have the meaning set forth in Section 4(b).(aa)“Original Employment Agreement” shall have the meaning set forth in the recitals hereto.(bb)“Partnership” means Summit Midstream Partners LP, a Delaware limited partnership.(cc)“Performance Targets” shall have the meaning set forth in Section 3(b).(dd)“Person” shall mean any individual, natural person, corporation (including any non-profit corporation), generalpartnership, limited partnership, limited liability partnership, joint venture, estate, trust, company (includingany company limited by shares, limited liability company or joint stock company), incorporated orunincorporated association, governmental authority, firm, society or other enterprise, organization or otherentity of any nature. EXH 10.12-4Execution Copy(ee)“Proprietary Information” shall have the meaning set forth in Section 7(d).(ff)“Public Offering” shall mean the first underwritten public offering of any equity securities of the Company or thePartnership pursuant to an effective registration statement filed by the Company with the Securities andExchange Commission (other than Form S-8 or successors to such form) under the Securities Act of1933, as amended.(gg)“Release” shall have the meaning set forth in Section 5(b)(ii).(hh)“Restricted Period” shall mean the period from the Effective Date through (i) with respect to any termination ofemployment (other than a termination of employment pursuant to Section 4(a)(vii) (Non-Extension ofTerm by the Company) or Section 4(a)(viii) (Non-Extension of Term by the Executive)), the first (1st)anniversary of the Date of Termination, and (ii) with respect to a termination of employment pursuant toSection 4(a)(vii) (Non-Extension of Term by the Company) or Section 4(a)(viii) (Non-Extension of Termby the Executive), the Date of Termination or, in the event that the Company exercises its NoncompeteOption, the date elected by the Company thereunder.(ii)“Section 409A” shall mean Section 409A of the Code and the Department of Treasury regulations and otherinterpretive guidance issued thereunder, including without limitation any such regulations or other guidancethat may be issued after the Effective Date.(jj)“Severance Payment” shall have the meaning set forth in Section 5(b)(i).(kk)“Severance Period” shall mean: (A) if the Executive’s employment shall be terminated by the Company withoutCause pursuant to Section 4(a)(iv) or by the Executive’s resignation for Good Reason pursuant to Section4(a)(v), the period beginning on the Date of Termination and ending on the first (1st) anniversary of theDate of Termination, and (B) if the Executive’s employment shall be terminated due to non-extension ofthe Initial Term or any Extension Term by the Company pursuant to Section 4(a)(vii) or by the Executivepursuant to Section 4(a)(viii), but only if the Company exercises its Noncompete Option in connection withsuch termination, the period beginning on the Date of Termination and ending on the expiration date of theRestricted Period (as elected by the Company pursuant to its Noncompete Option).(ll)“SMM LLC Agreement” shall mean that certain Limited Liability Company Agreement of Summit MidstreamManagement, LLC, a Delaware limited liability company, as it may be amended, modified or supplementedfrom time to time.(mm)“Term” shall have the meaning set forth in Section 2(b). EXH 10.12-5Execution Copy(nn) “Total Payments” shall have the meaning set forth in Section 6(b).2. Employment.(a) In General. The Company shall employ the Executive and the Executive shall enter the employ of the Company,for the period set forth in Section 2(b), in the position set forth in Section 2(c), and upon the other terms and conditions herein provided.(b) Term of Employment. The initial term of employment under this Agreement (the “Initial Term”) shall be for theperiod beginning on the Effective Date and ending on the third (3rd) anniversary of the Effective Date, unless earlier terminated asprovided in Section 4. The Initial Term shall automatically be extended for successive one (1) year periods (each, an “Extension Term”and, collectively with the Initial Term, the “Term”), unless either party hereto gives notice of non-extension to the other no later thanninety (90) days prior to the expiration of the then-applicable Term.(c) Position and Duties. During the Term, the Executive: (i) shall serve as Chief Commercial Officer of theCompany, with responsibilities, duties and authority customary for such position, subject to direction by the Chief Executive Officer ofthe Company; (ii) shall report directly to the Chief Executive Officer of the Company; (iii) shall devote substantially all theExecutive’s working time and efforts to the business and affairs of the Company and its subsidiaries, provided that the Executive may(1) serve on corporate, civic, charitable, industry or professional association boards or committees, subject to the Board’s prior writtenconsent in the case of any such board or committee that relates directly or indirectly to the business of the Company or its subsidiaries(which consent shall not unreasonably be withheld), (2) deliver lectures, fulfill speaking engagements or teach at educationalinstitutions and (3) manage his personal investments, so long as none of such activities meaningfully interferes with the performance ofthe Executive’s duties and responsibilities hereunder, or involves a conflict of interest with the Executive’s duties or responsibilitieshereunder or a breach of the covenants contained in Section 7; and (4) agrees to observe and comply with the Company’s rules andpolicies as adopted by the Company from time to time, which have been made available to the Executive.3. Compensation and Related Matters.(a) Annual Base Salary. During the Term, the Executive shall receive a base salary at a rate of $275,000 per annum,which shall be paid in accordance with the customary payroll practices of the Company, subject to review and upward, but notdownward, adjustment by the Board in its sole discretion (the “Annual Base Salary”).(b) Annual Bonus. With respect to each calendar year that ends during the Term, commencing with calendar year2012, the Executive shall be eligible to receive an annual cash bonus (the “Annual Bonus”) ranging from zero to one hundred fiftypercent (150%) of the EXH 10.12-6Execution CopyAnnual Base Salary, with a target Annual Bonus equal to seventy-five percent (75%) of the Annual Base Salary, based upon annualperformance targets (the “Performance Targets”) established by the Board in its sole discretion. The amount of the Annual Bonus shallbe based upon attainment of the Performance Targets, as determined by the Board (or any authorized committee of the Board) in its solediscretion. Each such Annual Bonus shall be payable on such date as is determined by the Board, but in any event on or prior to March15 of the calendar year immediately following the calendar year with respect to which such Annual Bonus relates. Notwithstanding theforegoing, no bonus shall be payable with respect to any calendar year unless the Executive remains continuously employed with theCompany during the period beginning on the Effective Date and ending on December 31 of such year.(c) Benefits. The Executive shall be eligible to participate in benefit plans, programs and arrangements of theCompany, as in effect from time to time (including, without limitation, medical and dental insurance and a 401(k) plan).(d) Vacation; Holidays. During the Term, the Executive shall be entitled to four (4) weeks paid vacation each fullcalendar year. Any vacation shall be taken at the reasonable and mutual convenience of the Company and the Executive. Holidays shallbe provided in accordance with Company policy, as in effect from time to time.(e) Business Expenses. During the Term, the Company shall reimburse the Executive for all reasonable travel andother business expenses incurred by the Executive in the performance of the Executive’s duties to the Company in accordance with theCompany’s applicable expense reimbursement policies and procedures.4. Termination. The Executive’s employment hereunder may be terminated by the Company or the Executive, as applicable, withoutany breach of this Agreement only under the following circumstances:(a) Circumstances(i) Death. The Executive’s employment hereunder shall terminate upon the Executive’s death.(ii) Disability. If the Executive incurs a Disability, the Company may give the Executive written notice of itsintention to terminate the Executive’s employment. In that event, the Executive’s employment with the Company shallterminate, effective on the later of the thirtieth (30th) day after receipt of such notice by the Executive or the date specified insuch notice; provided that within the thirty (30) day period following receipt of such notice, the Executive shall not havereturned to full-time performance of the Executive’s duties hereunder.(iii) Termination for Cause. The Company may terminate the Executive’s employment for Cause.(iv) Termination without Cause. The Company may terminate the Executive’s employment without Cause. EXH 10.12-7Execution Copy(v) Resignation for Good Reason. The Executive may resign from the Executive’s employment for GoodReason.(vi) Resignation without Good Reason. The Executive may resign from the Executive’s employment withoutGood Reason.(vii) Non-Extension of Term by the Company. The Company may give notice of non-extension to theExecutive pursuant to Section 2(b). For the avoidance of doubt, non-extension of the Term by the Company shall not constitutetermination by the Company without Cause.(viii) Non-Extension of Term by the Executive. The Executive may give notice of non-extension to theCompany pursuant to Section 2(b). For the avoidance of doubt, non-extension of the Term by the Executive shall not constituteresignation with Good Reason.(b) Notice of Termination. Any termination of the Executive’s employment by the Company or by the Executiveunder this Section 4 (other than a termination pursuant to Section 4(a)(i) above) shall be communicated by a written notice to the otherparty hereto: (i) indicating the specific termination provision in this Agreement relied upon, (ii) except with respect to a terminationpursuant to Sections 4(a)(iv), (vi), (vii) or (viii), setting forth in reasonable detail the facts and circumstances claimed to provide a basisfor termination of the Executive’s employment under the provision so indicated, and (iii) specifying a Date of Termination which, ifsubmitted by the Executive (or, in the case of a termination described in Section 4(a)(ii), by the Company), shall be at least thirty (30)days following the date of such notice (a “Notice of Termination”); provided, however, that a Notice of Termination delivered by theCompany pursuant to Section 4(a)(ii) shall not be required to specify a Date of Termination, in which case the Date of Termination shallbe determined pursuant to Section 4(a)(ii); and provided, further, that in the event that the Executive delivers a Notice of Termination(other than a notice of non-extension under Section 4(a)(viii) above) to the Company, the Company may, in its sole discretion, acceleratethe Date of Termination to any date that occurs following the date of Company’s receipt of such Notice of Termination (even if suchdate is prior to the date specified in such Notice of Termination). A Notice of Termination submitted by the Company may provide for aDate of Termination on the date the Executive receives the Notice of Termination, or any date thereafter elected by the Company in itssole discretion. The failure by the Company or the Executive to set forth in the Notice of Termination any fact or circumstance whichcontributes to a showing of Cause or Good Reason shall not waive any right of the Company or the Executive hereunder or preclude theCompany or the Executive from asserting such fact or circumstance in enforcing the Company’s or the Executive’s rights hereunder.5. Company Obligations Upon Termination of Employment.(a) In General. Upon a termination of the Executive’s employment for any reason, the Executive (or the Executive’sestate) shall be entitled to receive: (i) any portion of the Executive’s Annual Base Salary through the Date of Termination nottheretofore paid, (ii) any expenses owed to the Executive under Section 3(e), (iii) any accrued vacation pay owed to the EXH 10.12-8Execution CopyExecutive pursuant to Section 3(d), and (iv) any amount arising from the Executive’s participation in, or benefits under, any employeebenefit plans, programs or arrangements under Section 3(c), which amounts shall be payable in accordance with the terms andconditions of such employee benefit plans, programs or arrangements. Any Annual Bonus earned for any calendar year completed priorto the Date of Termination, but unpaid prior to such date, shall be paid within sixty (60) days after the Date of Termination (but in anyevent on or prior to March 15 of the calendar year immediately following such completed calendar year with respect to which suchAnnual Bonus was earned). Except as otherwise set forth in Section 5(b) below, the payments and benefits described in this Section 5(a)shall be the only payments and benefits payable in the event of the Executive’s termination of employment for any reason.(b) Severance Payment(i) In the event of the Executive’s termination of employment under the circumstances described below,then, in addition to the payments and benefits described in Section 5(a) above, the Company shall, during the Severance Period,pay to the Executive an amount (the “Severance Payment”) calculated as described below:(A) If the Executive’s employment shall be terminated by the Company without Cause pursuant to Section4(a)(iv) or by the Executive’s resignation for Good Reason pursuant to Section 4(a)(v), then the Severance Paymentshall be an amount equal to the sum of (1) the Annual Base Salary for the year in which the Date of Terminationoccurs, and (2) the Annual Bonus paid to the Executive in respect of the calendar year immediately preceding the yearin which the Date of Termination occurs.(B) If the Executive’s employment shall be terminated due to non-extension of the Initial Term or anyExtension Term by the Company pursuant to Section 4(a)(vii) or by the Executive pursuant to Section 4(a)(viii), butonly if the Company exercises its Noncompete Option in connection with such termination, then the SeverancePayment shall be an amount equal to (1) the sum of (x) the Annual Base Salary for the year in which the Date ofTermination occurs, and (y) the Annual Bonus paid to the Executive in respect of the calendar year immediatelypreceding the year in which the Date of Termination occurs, multiplied by (2) a fraction, the numerator of which isequal to the number of days from the Date of Termination through the expiration date of the Restricted Period (aselected by the Company pursuant to its Noncompete Option), and the denominator of which is 365.(ii) The Severance Payment shall be in lieu of notice or any other severance benefits to which the Executivemight otherwise be entitled. Notwithstanding anything herein to the contrary, (A) no portion of the Severance Payment shall bepaid unless, on or prior to the thirtieth (30th) day following the Date of Termination, the Executive timely executes a generalwaiver and release of claims agreement substantially in the form attached hereto as Exhibit A (the “Release”), which Releaseshall not have been revoked by the Executive prior to the expiration of the period (if any) during which any portion of suchRelease is revocable under applicable law, and (B) as of the first date EXH 10.12-9Execution Copyon which the Executive violates any covenant contained in Section 7, any remaining unpaid portion of the Severance Paymentshall thereupon be forfeited. Subject to the provisions of Section 9, the Severance Payment shall be paid in equal installmentsduring the Severance Period, at the same time and in the same manner as the Annual Base Salary would have been paid had theExecutive remained in active employment during the Severance Period, in accordance with the Company’s normal payrollpractices in effect on the Date of Termination; provided that any installment that would otherwise have been paid prior to thefirst normal payroll payment date occurring on or after the thirtieth (30th) day following the Date of Termination (such payrolldate, the “First Payment Date”) shall instead be paid on the First Payment Date. For purposes of Section 409A (including,without limitation, for purposes of Section 1.409A-2(b)(2)(iii) of the Department of Treasury Regulations), the Executive’sright to receive the Severance Payment in the form of installment payments (the “Installment Payments”) shall be treated as aright to receive a series of separate payments and, accordingly, each Installment Payment shall at all times be considered aseparate and distinct payment.(c) The provisions of this Section 5 shall supersede in their entirety any severance payment provisions in anyseverance plan, policy, program or other arrangement maintained by the Company.6. Change in Control.(a) Equity Awards. Notwithstanding anything to the contrary in this Agreement or any other agreement, including theLTIP and any award agreement thereunder, all equity awards granted to the Executive under the LTIP upon or following a PublicOffering and held by the Executive as of immediately prior to a Change in Control, to the extent unvested, shall become fully vestedimmediately prior to the Change in Control.(b) Golden Parachute Excise Tax Protection. Notwithstanding any provision of this Agreement, if any portion of thepayments or benefits provided to the Executive hereunder, or under any other agreement with the Executive or any plan, policy orarrangement of the Company or any of its Affiliates (in the aggregate, “Total Payments”), would constitute an “excess parachutepayment” and would, but for this Section 6(b), result in the imposition on the Executive of an excise tax under Section 4999 of theCode (the “Excise Tax”), then the Total Payments to be made to the Executive shall either be (i) delivered in full, or (ii) reduced bysuch amount such that no portion of the Total Payments would be subject to the Excise Tax, whichever of the foregoing results in thereceipt by the Executive of the greatest benefit on an after-tax basis (taking into account the applicable federal, state and local incometaxes and the Excise Tax). The determination of whether a reduction in Total Payments is necessary and the amount of any suchreduction shall be made by the Company in its reasonable discretion and in reliance on its tax advisors. If the Company so determines thata reduction in Total Payments is required, such reduction shall apply first pro rata to (A) cash payments subject to Section 409A of theCode as “deferred compensation” and (B) cash payments not subject to Section 409A of the Code (in each case with the cash paymentsotherwise scheduled to be paid latest in time reduced first), and then pro rata to (C) equity-based compensation subject to Section 409Aof the Code as “deferred compensation” and (D) equity-based compensation not subject to Section 409A of the Code. EXH 10.12-10Execution Copy7. Restrictive Covenants.(a) The Executive shall not, at any time during the Restricted Period, directly or indirectly engage in, have any equityinterest in, or manage or operate any person, firm, corporation, partnership, business or entity (whether as director, officer, employee,agent, representative, partner, security holder, consultant or otherwise) that engages in (either directly or through any subsidiary orAffiliate thereof) any business or activity (i) relating to midstream assets (including, without limitation, the gathering, processing andtransportation of natural gas and the transportation and storage of refined products other than natural gas) in North America, whichcompetes with the business of the Company or any entity owned by the Company, or (ii) which the Company or any of its Affiliates hastaken active steps to engage in or acquire, but only if the Executive directly or indirectly engages in, has any equity interest in, ormanages or operates, such business or activity (whether as director, officer, employee, agent, representative, partner, security holder,consultant or otherwise). Notwithstanding the foregoing, the Executive shall be permitted to acquire a passive stock or equity interest insuch a business; provided that such stock or other equity interest acquired is not more than five percent (5%) of the outstanding interestin such business.(b) The Executive shall not, at any time during the Term or during the twelve (12)-month period immediatelyfollowing the Date of Termination, directly or indirectly, either for himself or on behalf of any other entity, (i) recruit or otherwisesolicit or induce any employee, customer, subscriber or supplier of the Company to terminate its employment or arrangement with theCompany, or otherwise change its relationship with the Company, or (ii) hire, or cause to be hired, any person who was employed by theCompany at any time during the twelve (12)-month period immediately prior to the Date of Termination or who thereafter becomesemployed by the Company.(c) The provisions contained in Sections 7(a) and (b) may be altered and/or waived to be made less restrictive on theExecutive with the prior written consent of the Board or the Compensation Committee.(d) Except as the Executive reasonably and in good faith determines to be required in the faithful performance of theExecutive’s duties hereunder or in accordance with Section 7(f), the Executive shall, during the Term and after the Date ofTermination, maintain in confidence and shall not directly or indirectly, use, disseminate, disclose or publish, or use for the Executive’sbenefit or the benefit of any person, firm, corporation or other entity, any confidential or proprietary information or trade secrets of orrelating to the Company, including, without limitation, information with respect to the Company’s operations, processes, protocols,products, inventions, business practices, finances, principals, vendors, suppliers, customers, potential customers, marketing methods,costs, prices, contractual relationships, regulatory status, compensation paid to employees or other terms of employment (“ProprietaryInformation”), or deliver to any person, firm, corporation or other entity, any document, record, notebook, computer program or similarrepository of or containing any such Proprietary Information. The Executive’s obligation to maintain and not use, disseminate, disclose orpublish, or use for the Executive’s benefit or the benefit of any person, firm, corporation or other entity, any Proprietary Informationafter the Date of Termination will continue so long as such Proprietary Information is not, or has not by legitimate means become,generally known and in EXH 10.12-11Execution Copythe public domain (other than by means of the Executive’s direct or indirect disclosure of such Proprietary Information) and continues tobe maintained as Proprietary Information by the Company. The parties hereby stipulate and agree that as between them, the ProprietaryInformation identified herein is important, material and affects the successful conduct of the businesses of the Company (and anysuccessor or assignee of the Company).(e) Upon termination of the Executive’s employment with the Company for any reason, the Executive will promptlydeliver to the Company all correspondence, drawings, manuals, letters, notes, notebooks, reports, programs, plans, proposals, financialdocuments, or any other documents concerning the Company’s customers, business plans, marketing strategies, products or processes.(f) The Executive may respond to a lawful and valid subpoena or other legal process but shall give the Company (iflawfully permitted to do so) the earliest possible notice thereof, and shall, as much in advance of the return date as possible, makeavailable to the Company and its counsel the documents and other information sought, and shall assist such counsel in resisting orotherwise responding to such process. The Executive may also disclose Proprietary Information if: (i) in the reasonable written opinionof counsel for the Executive furnished to the Company, such information is required to be disclosed for the Executive not to be inviolation of any applicable law or regulation or (ii) the Executive is required to disclose such information in connection with theenforcement of any rights under this Agreement or any other agreements between the Executive and the Company.(g) The Executive agrees not to disparage the Company, any of its products or practices, or any of its directors,officers, agents, representatives, equity holders or Affiliates, either orally or in writing, at any time; provided that the Executive mayconfer in confidence with the Executive’s legal representatives, make truthful statements to any government agency in sworntestimony, or make truthful statements as otherwise required by law. The Company agrees that, upon the termination of theExecutive’s employment hereunder, it shall advise its directors and executive officers not to disparage the Executive, either orally or inwriting, at any time; provided that they may confer in confidence with the Company’s and their legal representatives and make truthfulstatements as required by law.(h) Prior to accepting other employment or any other service relationship during the Restricted Period, the Executiveshall provide a copy of this Section 7 to any recruiter who assists the Executive in obtaining other employment or any other servicerelationship and to any employer or person with which the Executive discusses potential employment or any other service relationship.(i) In the event the terms of this Section 7 shall be determined by any court of competent jurisdiction to beunenforceable by reason of its extending for too great a period of time or over too great a geographical area or by reason of its being tooextensive in any other respect, it will be interpreted to extend only over the maximum period of time for which it may be enforceable,over the maximum geographical area as to which it may be enforceable, or to the maximum extent in all other respects as to which itmay be enforceable, all as determined by such court in such action. EXH 10.12-12Execution Copy(j) As used in this Section 7, the term “Company” shall include the Company, its parent, related entities, and any of itsdirect or indirect subsidiaries.8. Injunctive Relief. The Executive recognizes and acknowledges that a breach of the covenants contained in Section 7 will causeirreparable damage to the Company and its goodwill, the exact amount of which will be difficult or impossible to ascertain, and that theremedies at law for any such breach will be inadequate. Accordingly, the Executive agrees that in the event of a breach of any of thecovenants contained in Section 7, in addition to any other remedy which may be available at law or in equity, the Company will beentitled to specific performance and injunctive relief.9. Section 409A.(a) General. The parties hereto acknowledge and agree that, to the extent applicable, this Agreement shall beinterpreted in accordance with, and incorporate the terms and conditions required by, Section 409A. Notwithstanding any provision ofthis Agreement to the contrary, in the event that the Company determines that any amounts payable hereunder will be immediatelytaxable to the Executive under Section 409A, the Company reserves the right to (without any obligation to do so or to indemnify theExecutive for failure to do so) (i) adopt such amendments to this Agreement or adopt such other policies and procedures (includingamendments, policies and procedures with retroactive effect) that it determines to be necessary or appropriate to preserve the intendedtax treatment of the benefits provided by this Agreement, to preserve the economic benefits of this Agreement and to avoid lessfavorable accounting or tax consequences for the Company and/or (ii) take such other actions it determines to be necessary or appropriateto exempt the amounts payable hereunder from Section 409A or to comply with the requirements of Section 409A and thereby avoidthe application of penalty taxes thereunder. Notwithstanding anything herein to the contrary, no provision of this Agreement shall beinterpreted or construed to transfer any liability for failure to comply with the requirements of Section 409A from the Executive or anyother individual to the Company or any of its Affiliates, employees or agents.(b) Separation from Service under Section 409A; Section 409A Compliance. Notwithstanding anything herein to thecontrary: (i) no termination or other similar payments and benefits hereunder shall be payable unless the Executive’s termination ofemployment constitutes a “separation from service” within the meaning of Section 1.409A-1(h) of the Department of TreasuryRegulations; (ii) if the Executive is deemed at the time of the Executive’s separation from service to be a “specified employee” forpurposes of Section 409A(a)(2)(B)(i) of the Code, to the extent delayed commencement of any portion of any termination or othersimilar payments and benefits to which the Executive may be entitled hereunder (after taking into account all exclusions applicable tosuch payments or benefits under Section 409A) is required in order to avoid a prohibited distribution under Section 409A(a)(2)(B)(i) ofthe Code, such portion of such payments and benefits shall not be provided to the Executive prior to the earlier of (x) the expiration ofthe six (6)-month period measured from the date of the Executive’s “separation from service” with the Company (as such term isdefined in the Department of Treasury Regulations issued under Section 409A) or (y) the date of the Executive’s death; provided thatupon the earlier of such dates, all payments and benefits deferred pursuant to this Section 9(b)(ii) shall be paid in a lump sum to theExecutive, and any EXH 10.12-13Execution Copyremaining payments and benefits due hereunder shall be provided as otherwise specified herein; (iii) the determination of whether theExecutive is a “specified employee” for purposes of Section 409A(a)(2)(B)(i) of the Code as of the time of the Executive’s separationfrom service shall be made by the Company in accordance with the terms of Section 409A (including, without limitation, Section1.409A-1(i) of the Department of Treasury Regulations and any successor provision thereto); (iv) to the extent that any InstallmentPayments under this Agreement are deemed to constitute “nonqualified deferred compensation” within the meaning of Section 409A,for purposes of Section 409A (including, without limitation, for purposes of Section 1.409A-2(b)(2)(iii) of the Department of TreasuryRegulations), each such payment that the Executive may be eligible to receive under this Agreement shall be treated as a separate anddistinct payment; (v) to the extent that any reimbursements or corresponding in-kind benefits provided to the Executive under thisAgreement are deemed to constitute “deferred compensation” under Section 409A, such reimbursements or benefits shall be providedreasonably promptly, but in no event later than December 31 of the year following the year in which the expense was incurred, and inany event in accordance with Section 1.409A-3(i)(1)(iv) of the Department of Treasury Regulations; and (vi) the amount of any suchpayments or expense reimbursements in one calendar year shall not affect the expenses or in-kind benefits eligible for payment orreimbursement in any other calendar year, other than an arrangement providing for the reimbursement of medical expenses referred toin Section 105(b) of the Code, and the Executive’s right to such payments or reimbursement of any such expenses shall not be subjectto liquidation or exchange for any other benefit. EXH 10.12-14Execution Copy10. Assignment and Successors. The Company may assign its rights and obligations under this Agreement to any entity, includingany successor to all or substantially all the assets of the Company, by merger or otherwise, and may assign or encumber this Agreementand its rights hereunder as security for indebtedness of the Company and its Affiliates. The Executive may not assign the Executive’srights or obligations under this Agreement to any individual or entity. This Agreement shall be binding upon and inure to the benefit ofthe Company, the Executive and their respective successors, assigns, personnel and legal representatives, executors, administrators,heirs, distributees, devisees, and legatees, as applicable.11. Governing Law. This Agreement shall be governed, construed, interpreted and enforced in accordance with the substantive lawsof the State of Delaware, without reference to the principles of conflicts of law of Delaware or any other jurisdiction, and whereapplicable, the laws of the United States.12. Validity. The invalidity or unenforceability of any provision or provisions of this Agreement shall not affect the validity orenforceability of any other provision of this Agreement, which shall remain in full force and effect.13. Notices. Any notice, request, claim, demand, document and other communication hereunder to any party hereto shall beeffective upon receipt (or refusal of receipt) and shall be in writing and delivered personally or sent by telex, telecopy, or certified orregistered mail, postage prepaid, to the following address (or at any other address as any party hereto shall have specified by notice inwriting to the other party hereto):(a) If to the Company:Summit Midstream Partners, LLC2100 McKinney AvenueSuite 1250Dallas, Texas 75214Attn: Brock DegeyterFacsimile: (214) 462-7716with copies to:Energy Capital Partners51 John F. Kennedy Parkway, Suite 200 Short Hills, New Jersey 07078Attn: Andrew MakkFacsimile: (973) 671-6101 EXH 10.12-15Execution Copyand:Energy Capital Partners11943 El Camino Real, Suite 220San Diego, California 92130Attn: Andrew D. SingerFacsimile: (858) 703-4401and:Latham & Watkins LLP885 Third AvenueNew York, New York 10022-4802Attn: Jed W. BricknerFacsimile: (212) 751-4864(b) If to the Executive, at the address set forth on the signature page hereto. EXH 10.12-16Execution Copy14. Counterparts. This Agreement may be executed in several counterparts, each of which shall be deemed to be an original, but allof which together will constitute one and the same Agreement.15. Entire Agreement. This Agreement (together with any other agreements and instruments contemplated hereby or referred toherein) is intended by the parties hereto to be the final expression of their agreement with respect to the employment of the Executiveby the Company and may not be contradicted by evidence of any prior or contemporaneous agreement (including, without limitation,any term sheet or offer letter). The parties hereto further intend that this Agreement shall constitute the complete and exclusivestatement of its terms and that no extrinsic evidence whatsoever may be introduced in any judicial, administrative, or other legalproceeding to vary the terms of this Agreement. This Agreement expressly supersedes the Original Employment Agreement.16. Amendments; Waivers. This Agreement may not be modified, amended, or terminated except by an instrument in writing,signed by the Executive and a duly authorized officer of the Company and approved by the Board, which expressly identifies theamended provision of this Agreement. By an instrument in writing similarly executed and approved by the Board, the Executive or aduly authorized officer of the Company may waive compliance by the other party or parties hereto with any provision of this Agreementthat such other party was or is obligated to comply with or perform; provided, however, that such waiver shall not operate as a waiver of,or estoppel with respect to, any other or subsequent failure to comply or perform. No failure to exercise and no delay in exercising anyright, remedy, or power hereunder shall preclude any other or further exercise of any other right, remedy, or power provided herein orby law or in equity.17. No Inconsistent Actions. The parties hereto shall not voluntarily undertake or fail to undertake any action or course of actioninconsistent with the provisions or essential intent of this Agreement. Furthermore, it is the intent of the parties hereto to act in a fair andreasonable manner with respect to the interpretation and application of the provisions of this Agreement.18. Construction. This Agreement shall be deemed drafted equally by both of the parties hereto. Its language shall be construed as awhole and according to its fair meaning. Any presumption or principle that the language is to be construed against any party hereto shallnot apply. The headings in this Agreement are only for convenience and are not intended to affect construction or interpretation. Anyreferences to paragraphs, subparagraphs, sections or subsections are to those parts of this Agreement, unless the context clearly indicatesto the contrary. Also, unless the context clearly indicates to the contrary, (a) the plural includes the singular and the singular includesthe plural; (b) “and” and “or” are each used both conjunctively and disjunctively; (c) “any,” “all,” “each,” or “every” means “any andall,” and “each and every”; (d) ”includes” and “including” are each “without limitation”; (e) “herein,” “hereof,” “hereunder” and othersimilar compounds of the word “here” refer to the entire Agreement and not to any particular paragraph, subparagraph, section orsubsection; and (f) all pronouns and any variations thereof shall be deemed to refer to the masculine, feminine, neuter, singular or pluralas the identity of the entities or persons referred to may require. EXH 10.12-17Execution Copy19. Arbitration. Any dispute or controversy based on, arising under or relating to this Agreement shall be settled exclusively by finaland binding arbitration, conducted before a single neutral arbitrator in Dallas, Texas in accordance with the Employment ArbitrationRules and Mediation Procedures of the American Arbitration Association (the “AAA”) then in effect. Arbitration may be compelled, andjudgment may be entered on the arbitration award in any court having jurisdiction; provided, however, that the Company shall beentitled to seek a restraining order or injunction in any court of competent jurisdiction to prevent any continuation of any violation of theprovisions of Section 7, and the Executive hereby consents that such restraining order or injunction may be granted without requiringthe Company to post a bond. Only individuals who are (a) lawyers engaged full-time in the practice of law and (b) on the AAA roster ofarbitrators shall be selected as an arbitrator. Within twenty (20) days of the conclusion of the arbitration hearing, the arbitrator shallprepare written findings of fact and conclusions of law. The arbitrator shall be entitled to award any relief available in a court of law.Each party shall bear its own costs and attorneys’ fees in connection with an arbitration; provided that the Company shall bear the cost ofthe arbitrator and the AAA’s administrative fees.20. Enforcement. If any provision of this Agreement is held to be illegal, invalid or unenforceable under present or future lawseffective during the term of this Agreement, such provision shall be fully severable; this Agreement shall be construed and enforced asif such illegal, invalid or unenforceable provision had never comprised a portion of this Agreement; and the remaining provisions of thisAgreement shall remain in full force and effect and shall not be affected by the illegal, invalid or unenforceable provision or by itsseverance from this Agreement. Furthermore, in lieu of such illegal, invalid or unenforceable provision there shall be addedautomatically as part of this Agreement a provision as similar in terms to such illegal, invalid or unenforceable provision as may bepossible and be legal, valid and enforceable.21. Withholding. The Company shall be entitled to withhold from any amounts payable under this Agreement, any federal, state,local or foreign withholding or other taxes or charges which the Company is required to withhold. The Company shall be entitled to relyon an opinion of counsel if any questions as to the amount or requirement of withholding shall arise.22. Absence of Conflicts; Executive Acknowledgement. The Executive hereby represents that from and after the Effective Datethe performance of the Executive’s duties hereunder will not breach any other agreement to which the Executive is a party. TheExecutive acknowledges that the Executive has read and understands this Agreement, is fully aware of its legal effect, has not acted inreliance upon any representations or promises made by the Company other than those contained in writing herein, and has entered intothis Agreement freely based on the Executive’s own judgment.23. Survival. The expiration or termination of the Term shall not impair the rights or obligations of any party hereto which shall haveaccrued prior to such expiration or termination.[Signature pages follow] EXH 10.12-18Execution CopyIN WITNESS WHEREOF, the parties hereto have executed this Agreement on the date and year first above written.COMPANYBy:/s/ Steven J. NewbyName: Steven J. NewbyTitle: President and Chief Executive OfficerSignature Page to the Employment Agreement for Brad Graves--FinalEXH 10.12-19EXECUTIVEBy:/s/ Brad N. GravesBrad N. GravesResidence Address:13607 LakeHills View CircleCypress, Texas 77429Signature Page to the Employment Agreement for Brad Graves--FinalEXH 10.12-20EXHIBIT AForm of ReleaseBrad Graves (the “Executive”) agrees for the Executive, the Executive’s spouse and child or children (if any), theExecutive’s heirs, beneficiaries, devisees, executors, administrators, attorneys, personal representatives, successors and assigns, herebyforever to release, discharge, and covenant not to sue Summit Midstream Partners, LLC, a Delaware limited liability company (the“Company”), and any of its past, present, or future parent, affiliated, related, and/or subsidiary entities, and all of the past and presentdirectors, shareholders, officers, general or limited partners, employees, agents, and attorneys, and agents and representatives of suchentities, and employee benefit plans in which the Executive is or has been a participant by virtue of his employment with the Company(collectively, the “Releasees”), from any and all claims, debts, demands, accounts, judgments, rights, causes of action, equitable relief,damages, costs, charges, complaints, obligations, promises, agreements, controversies, suits, expenses, compensation, responsibility andliability of every kind and character whatsoever (including attorneys’ fees and costs), whether in law or equity, known or unknown,asserted or unasserted, suspected or unsuspected, which the Executive has or may have had against such Releasees based on any eventsor circumstances arising or occurring on or prior to the date this release (the “Release”) is executed, arising directly or indirectly out of,relating to, or in any other way involving in any manner whatsoever, (a) the Executive’s employment with the Company or itssubsidiaries or the termination thereof or (b) the Executive’s status at any time as a holder of any securities of the Company, and any andall claims arising under federal, state, or local laws relating to employment, or securities, including without limitation claims ofwrongful discharge, breach of express or implied contract, fraud, misrepresentation, defamation, or liability in tort, claims of any kindthat may be brought in any court or administrative agency, any claims arising under Title VII of the Civil Rights Act of 1964, the AgeDiscrimination in Employment Act, the Americans with Disabilities Act, the Fair Labor Standards Act, the Employee RetirementIncome Security Act, the Family and Medical Leave Act, the Securities Act of 1933, the Securities Exchange Act of 1934, theSarbanes-Oxley Act, and similar state or local statutes, ordinances, and regulations; provided, however, notwithstanding anything to thecontrary set forth herein, that this Release shall not extend to (i) benefit claims under employee pension or welfare benefit plans inwhich the Executive is a participant by virtue of his employment with the Company or its subsidiaries, (ii) any rights under that certainAmended and Restated Employment Agreement, dated as of [__], 2012, by and between the Company and the Executive, (iii) anyrights of indemnification the Executive may have under any written agreement between the Executive and the Company (or itsaffiliates), the Company’s Certificate of Incorporation, its LP Agreement, the General Corporation Law of the State of Delaware, anyapplicable statute or common law, or pursuant to any applicable insurance policy, (iv) unemployment compensation, (v) contractualrights to vested equity awards, (vi) COBRA benefits and (viii) any rights that may not be waived as a matter of law.The Executive understands that this Release includes a release of claims arising under the Age Discrimination inEmployment Act (ADEA). The Executive understands and warrants that he has been given a period of 21 days to review and considerthis Release. The Executive further warrants that he understands that he may use as much or all of his 21-day period as he wishesbefore signing, and warrants that he has done so. The Executive furtherA-1EXH 10.12-21warrants that he understands that, with respect to the release of age discrimination claims only, he/ has a period of seven days afterexecuting on the second signature line below to revoke the release of age discrimination claims by notice in writing to the Company.The Executive is hereby advised to consult with an attorney prior to executing this Release. By his signature below, theExecutive warrants that he has had the opportunity to do so and to be fully and fairly advised by that legal counsel as to the terms of thisRelease.ACKNOWLEDGEMENT (AS TO ALL CLAIMS OTHER THAN AGE DISCRIMINATION CLAIMS)The undersigned, having had full opportunity to review this Release with counsel of his choosing, signifies his agreement to theterms of this Release (other than as it relates to age discrimination claims) by his signature below. /s/ Brad Graves March 8, 2013Brad Graves DateACKNOWLEDGEMENT (AGE DISCRIMINATION CLAIMS)The undersigned, having had full opportunity to review this Release with counsel of his choosing, signifies his agreement to theterms of this Release (as it relates to age discrimination claims) by his signature below. /s/ Brad Graves March 8, 2013Brad Graves DateA-2EXH 10.12-22EXHIBIT 23.1CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMWe consent to the incorporation by reference in Registration Statement No. 333-184214 on Form S-8 of our report dated March 18, 2013,relating to the consolidated financial statements of Summit Midstream Partners, LP and subsidiaries (which report expresses an unqualifiedopinion and includes an explanatory paragraph regarding the acquisition of Grand River Gathering Company, LLC from Encana Corporationon October 27, 2011) appearing in this Annual Report on Form 10-K of Summit Midstream Partners, LP for the year ended December 31,2012./s/ Deloitte & Touche LLPDallas, TexasMarch 18, 2013EXH 23.1-1EXHIBIT 31.1CERTIFICATIONSI, Steven J. Newby, certify that:1. I have reviewed this annual report on Form 10-K of Summit Midstream Partners, LP;2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary tomake the statements made, in light of the circumstances under which such statements were made, not misleading with respect to theperiod covered by this report;3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (asdefined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to usby others within those entities, particularly during the period in which this report is being prepared;(b) Paragraph omitted pursuant to Rule 13a-14(a) of the General Rules and Regulations promulgated under the Securities ExchangeAct of 1934;(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions aboutthe effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;and(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant'smost recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or isreasonably likely to materially affect, the registrant's internal control over financial reporting; and5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financialreporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalentfunctions):(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant'sinternal control over financial reporting.Date: March 18, 2013 /s/ Steven J. Newby Steven J. Newby President, Chief Executive Officer and Director ofSummit Midstream GP, LLC (the general partner ofSummit Midstream Partners, LP)EXH 31.1-1EXHIBIT 31.2CERTIFICATIONSI, Matthew S. Harrison, certify that:1.I have reviewed this annual report on Form 10-K of Summit Midstream Partners, LP;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material factnecessary to make the statements made, in light of the circumstances under which such statements were made, not misleading withrespect to the period covered by this report;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in allmaterial respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in thisreport;4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures(as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to usby others within those entities, particularly during the period in which this report is being prepared;(b) Paragraph omitted pursuant to Rule 13a-14(a) of the General Rules and Regulations promulgated under the Securities ExchangeAct of 1934;(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions aboutthe effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;and(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’smost recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or isreasonably likely to materially affect, the registrant’s internal control over financial reporting; and5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financialreporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalentfunctions):(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’sinternal control over financial reporting.Date: March 18, 2013 /s/ Matthew S. Harrison Matthew S. Harrison Senior Vice President and Chief Financial Officer ofSummit Midstream GP, LLC (the general partner ofSummit Midstream Partners, LP)EXH 31.2-1EXHIBIT 32.1CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002In connection with the annual report on Form 10-K of Summit Midstream Partners, LP (the “Registrant”) for the annual period endedDecember 31, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, Steven J.Newby, as President, Chief Executive Officer and Director of Summit Midstream GP, LLC, the general partner of the Registrant, andMatthew S. Harrison, as Senior Vice President and Chief Financial Officer of Summit Midstream GP, LLC, the general partner of theRegistrant, each hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002,that, to his knowledge:(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operationsof the Registrant. /s/ Steven J. NewbyName: Steven J. NewbyTitle: President, Chief Executive Officer and Director of Summit Midstream GP, LLC (the general partnerof Summit Midstream Partners, LP)Date: March 18, 2013 /s/ Matthew S. HarrisonName: Matthew S. HarrisonTitle: Senior Vice President and Chief Financial Officer of Summit Midstream GP, LLC (the generalpartner of Summit Midstream Partners, LP)Date: March 18, 2013EXH 32.1-1

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