Summit Midstream Partners S1 IPO registration | SMLP 21 Aug 12

Summit Midstream Partners (SMLP) S-1IPO registration

Exhibit 99.2

As confidentially submitted to the Securities and Exchange Commission on July 17, 2012

Registration No. 333-

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Confidential Draft Submission No. 2

Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

Summit Midstream Partners, LP
(Exact Name of Registrant as Specified in its Charter)


Delaware (State or Other Jurisdiction of Incorporation or Organization)		4922 (Primary Standard Industrial Classification Code Number)		45-5200503 (I.R.S. Employer Identification Number)

2100 McKinney Avenue
Suite 1250
Dallas, Texas 75201
(214) 242-1955
(Address, including Zip Code, and Telephone Number, including
Area Code, of Registrant's Principal Executive Offices)

Brock M. Degeyter
Senior Vice President and General Counsel
2100 McKinney Avenue
Suite 1250
Dallas, TX 75201
(214) 242-1955
(Name, Address, including Zip Code, and Telephone Number, including
Area Code, of Agent for Service)


Copies to:
William N. Finnegan IV Brett E. Braden Latham & Watkins LLP 811 Main Street, Suite 3700 Houston, Texas 77002 (713) 546-5400		Joshua Davidson Baker Botts L.L.P. 910 Louisiana Street Houston, Texas 77002 (713) 229-1527

Approximate date of commencement of proposed sale to the public:
As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.o

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.o

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.o

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):


Large Accelerated Filer o		Accelerated Filer o		Non-Accelerated Filer ý (Do not check if a smaller reporting company)		Smaller Reporting Company o

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Proposed Maximum Aggregate Offering Price(1)(2)	Amount of Registration Fee




Common units representing limited partner interests	$	$

(1): Includes common units issuable upon exercise of the underwriters' option to purchase additional common units.
(2): Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to Completion, dated July 17, 2012

PROSPECTUS

Summit Midstream Partners, LP

Common Units
Representing Limited Partner Interests

This is the initial public offering of our common units representing limited partner interests. We are offering common units in this offering. We currently expect that the initial public offering price will be between $ and $ per common unit. Prior to this offering, there has been no public market for our common units.

We intend to apply to list our common units on the New York Stock Exchange under the symbol "SMLP."

We are an "emerging growth company" as defined in Section 101 of the Jumpstart Our Business Startups Act, or JOBS Act.

Investing in our common units involves risks. Please read "Risk Factors" beginning on page 20.

These risks include the following:

•: We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution or any distribution to holders of our common and subordinated units.
•: On a historical as adjusted basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our units for the year ended December 31, 2011 and for the twelve months ended March 31, 2012.
•: We depend on a relatively small number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, or the curtailment of production by, any one or more of these customers could materially adversely affect our revenues, cash flow and ability to make distributions to our unitholders.
•: We gather natural gas from the Piceance Basin and the Barnett Shale. Due to our lack of industry and geographic diversification, adverse developments in our existing areas of operation could materially adversely impact our financial condition, results of operations and cash flows and reduce our ability to make cash distributions to our unitholders.
•: Significant prolonged changes in natural gas prices could affect supply and demand, reducing throughput on our systems and materially adversely affecting our revenues and cash available to make distributions to our unitholders over the long-term.
•: Because of the natural decline in production from existing wells in our areas of operation, our success depends in part on our customers replacing declining production and also on our ability to maintain levels of throughput on our systems. Any decrease in the volumes of natural gas that we gather could materially adversely affect our business and operating results.
•: Summit Midstream Partners, LLC, which we refer to as "Summit Investments," owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations and has limited duties to us and our unitholders. Summit Investments and our general partner have conflicts of interest with us and they may favor their own interests to the detriment of us and our other unitholders.
•: Our partnership agreement restricts the rights of holders of our common units with respect to actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
•: Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
•: Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.
•: There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the market price of our common units may fluctuate significantly, and you could lose all or part of your investment.
•: You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

	Per Common Unit	Total

Initial Public Offering Price	$	$
Underwriting Discounts and Commissions(1)	$	$
Proceeds to Summit Midstream Partners, LP (before expenses)	$	$

(1): Excludes a structuring fee payable to Barclays Capital Inc. that is equal to % of the gross proceeds of this offering. Please see "Underwriting."

We have granted the underwriters the option to purchase up to an additional common units on the same terms and conditions set forth above if the underwriters sell more than common units in this offering.

Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the common units to purchasers on or about , 2012, through the book-entry facilities of The Depository Trust Company.


Barclays		BofA Merrill Lynch
Goldman, Sachs & Co.		Morgan Stanley

Prospectus dated , 2012

TABLE OF CONTENTS

		Page

Summary		1
Overview		1
Recent Trends		3
Business Strategies		4
Competitive Strengths		5
Our Sponsors		6
Risk Factors		6
Formation Transactions and Partnership Structure		7
Ownership of Summit Midstream Partners, LP		9
Our Management		10
Principal Executive Offices and Internet Address		10
Summary of Conflicts of Interest and Duties		10
Implications of Being an Emerging Growth Company		11
The Offering		13
Summary Historical Financial and Operating Data		17
Risk Factors		20
Risks Related to our Business		20
Risks Inherent in an Investment in Us		41
Tax Risks		52
Use of Proceeds		57
Capitalization		58
Dilution		59
Our Cash Distribution Policy and Restrictions on Distributions		60
General		60
Our Minimum Quarterly Distribution		61
Unaudited Historical As Adjusted Cash Available for Distribution for the Year Ended December 31, 2011		63
Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2013		66
Assumptions and Considerations		69
Provisions of Our Partnership Agreement Relating to Cash Distributions		76
Distributions of Available Cash		76
Operating Surplus and Capital Surplus		77
Capital Expenditures		79
Subordination Period		80
Distributions of Available Cash from Operating Surplus during the Subordination Period		82
Distributions of Available Cash from Operating Surplus after the Subordination Period		82
General Partner Interest and Incentive Distribution Rights		83
Percentage Allocations of Available Cash from Operating Surplus		83
General Partner's Right to Reset Incentive Distribution Levels		84
Distributions from Capital Surplus		87
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels		88
Distributions of Cash Upon Liquidation		88
Selected Historical Financial and Operating Data		91
Non-GAAP Financial Measure		93
Management's Discussion and Analysis of Financial Condition and Results of Operations		96
Overview		96
Our Operations		96
How We Evaluate Our Operations		98

		Page

General Trends and Outlook		100
Results of Operations—Combined Overview		102
Liquidity and Capital Resources		108
Quantitative and Qualitative Disclosures about Market Risk		113
Impact of Seasonality		114
Critical Accounting Policies and Estimates		114
Industry Overview		117
General		117
Midstream Services		117
Contractual Arrangements		118
Market Fundamentals		119
Business		123
Overview		123
Business Strategies		125
Competitive Strengths		126
Our Sponsors		128
Our Assets		128
Gas Gathering Agreements		132
Competition		133
Safety and Maintenance		134
Regulation of the Oil and Natural Gas Industries		135
Environmental Matters		138
Title to Properties and Rights-of-Way		144
Employees		144
Legal Proceedings		144
Management		145
Management of Summit Midstream Partners, LP		145
Director Independence		145
Committees of the Board of Directors		145
Directors and Executive Officers		146
Executive Compensation		148
Summary Compensation Table for 2011		149
Outstanding Equity Awards at December 31, 2011		151
2012 Long-Term Incentive Plan		153
Security Ownership of Certain Beneficial Owners and Management		155
Certain Relationships and Related Party Transactions		158
Distributions and Payments to our General Partner and its Affiliates		158
Agreements with Affiliates		159
Procedures for Review, Approval and Ratification of Related-Person Transactions		160
Conflicts of Interest and Duties		161
Conflicts of Interest		161
Duties of Our General Partner		167
Description of Our Common Units		171
The Units		171
Transfer Agent and Registrar		171
Transfer of Common Units		171
The Partnership Agreement		173
Organization and Duration		173
Purpose		173
Cash Distributions		173

		Page

Capital Contributions		173
Voting Rights		174
Limited Liability		175
Issuance of Additional Securities		176
Amendment of Our Partnership Agreement		177
Merger, Sale or Other Disposition of Assets		179
Termination and Dissolution		180
Liquidation and Distribution of Proceeds		180
Withdrawal or Removal of Our General Partner		180
Transfer of General Partner Interest		182
Transfer of Ownership Interests in Our General Partner		182
Transfer of Incentive Distribution Rights		182
Change of Management Provisions		182
Limited Call Right		182
Meetings; Voting		183
Status as Limited Partner		184
Non-Citizen Assignees; Redemption		184
Non-Taxpaying Assignees; Redemption		184
Indemnification		185
Reimbursement of Expenses		185
Books and Reports		185
Right to Inspect Our Books and Records		186
Registration Rights		186
Units Eligible For Future Sale		187
Material Federal Income Tax Consequences		188
Partnership Status		189
Limited Partner Status		190
Tax Consequences of Unit Ownership		190
Tax Treatment of Operations		197
Disposition of Common Units		198
Uniformity of Units		200
Tax-Exempt Organizations and Other Investors		201
Administrative Matters		202
Recent Legislative Developments		204
State, Local, Foreign and Other Tax Considerations		205
Investment in Summit Midstream Partners, LP by Employee Benefit Plans		206
Underwriting		208
Validity of the Common Units		215
Experts		215
Where You Can Find More Information		215
Forward-Looking Statements		216
Index to Financial Statements		F-1
Appendix A First Amended and Restated Agreement of Limited Partnership of Summit Midstream Partners, LP		A-1
Appendix B Glossary Of Terms		B-1

You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. Neither we nor the underwriters have authorized anyone to provide you with additional or different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making

iii

an offer to sell these securities in any jurisdiction where the offer or sale is not permitted. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front of this prospectus.

Industry and Market Data

The data included in this prospectus regarding the midstream natural gas industry, including descriptions of trends in the market and our position and the position of our competitors within the industry, is based on a variety of sources, including independent industry publications, government publications and other published independent sources, information obtained from customers, distributors, suppliers and trade and business organizations and publicly available information, as well as our good faith estimates, which have been derived from management's knowledge and experience in the industry in which we operate. Although we have not independently verified the accuracy or completeness of the third-party information included in this prospectus, based on management's knowledge and experience we believe that the third-party sources are reliable and that the third-party information included in this prospectus or in our estimates is accurate and complete.

SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical financial statements and related notes contained herein, before investing in our common units. The information presented in this prospectus assumes (1) an initial public offering price of $ per common unit and (2) unless otherwise indicated, that the underwriters' option to purchase additional common units is not exercised. You should read "Risk Factors" beginning on page 20 for more information about important risks that you should consider carefully before investing in our common units.

Unless the context otherwise requires, references in this prospectus to "Summit Midstream Partners, LP," the "partnership," "we," "our," "us" or like terms (i) for periods prior to September 3, 2009, are to the subsidiary we acquired from a subsidiary of Energy Future Holdings Corp., or Energy Future Holdings, as of that date, which we refer to as our "Initial Predecessor," (ii) for periods from September 3, 2009 to the closing of this offering, are to Summit Midstream Partners, LLC and its subsidiaries, which we refer to as the "Summit Midstream Predecessor," and together with our Initial Predecessor, our "Predecessor," and (iii) for periods from and after the closing of this offering, are to Summit Midstream Partners, LP and its subsidiaries after giving effect to the formation transactions described under "—Formation Transactions and Partnership Structure" on page 8 of this prospectus. References to "Summit GP" or our "general partner" are to Summit Midstream GP, LLC, a Delaware limited liability company and our general partner; references to "Energy Capital Partners" are to Energy Capital Partners II, LP and its parallel and co-investment funds; references to "GE Energy Financial Services" are to GE Energy Financial Services, Inc. and its subsidiaries and affiliates, other than Summit Midstream Partners, LLC, our general partner and us; and references to "Summit Investments" are to Summit Midstream Partners, LLC, a Delaware limited liability company owned by Energy Capital Partners, GE Energy Financial Services and certain members of our management team. We include as Appendix B a glossary of some of the terms we use in this prospectus.

Summit Midstream Partners, LP

Overview

We are a growth-oriented limited partnership focused on owning and operating midstream energy infrastructure that is strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in North America. We currently provide fee-based natural gas gathering and compression services in two unconventional resource basins: (i) the Piceance Basin, which includes the Mesaverde, Mancos and Niobrara Shale formations in western Colorado; and (ii) the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas. As of May 31, 2012, our gathering systems had approximately 386 miles of pipeline and 147,600 horsepower of compression. During the first quarter of 2012, our systems gathered an average of approximately 908 MMcf/d of natural gas, of which approximately 62% contained natural gas liquids, or NGLs, that were extracted by a third party processor. We believe that we are positioned to grow through the increased utilization and further development of our existing assets. In addition, we intend to grow our business through strategic partnerships with large producers to provide midstream services for their upstream development projects, as well as through acquisitions in our existing areas of operation and in new areas.

We generate a substantial majority of our revenue under long-term, fee-based natural gas gathering agreements. Our customers include some of the largest natural gas producers in North America, such as Encana Corporation, Chesapeake Energy Corporation, TOTAL, S.A., Carrizo Oil & Gas, Inc., WPX Energy, Inc., Bill Barrett Corporation, Exxon Mobil Corporation and EOG Resources, Inc.

systems. The minimum volume commitments, which totaled 2.6 Tcf at March 31, 2012 and, through 2020, average approximately 643 MMcf/d, are designed to ensure that we will generate a certain amount of revenue from each customer over the life of the respective gas gathering agreement, whether by collecting gathering fees on actual throughput or from cash payments to cover any minimum volume commitment shortfall. Our minimum volume commitments have original terms that range from 7 years to 15 years and, as of March 31, 2012, had a weighted average remaining life of 11.6 years assuming minimum throughput volumes for the remainder of the term. The fee-based nature of these agreements enhances the stability of our cash flows by limiting our direct commodity price exposure.

We were formed in 2009 by members of our management team and Energy Capital Partners, which together with its affiliated funds, is a private equity firm with over $7.0 billion in capital commitments that is focused on investing in North America's energy infrastructure. We are currently owned by Energy Capital Partners, GE Energy Financial Services, a global investor in essential, long-lived and capital-intensive energy assets with over $20 billion in energy investments worldwide, and certain members of our management team.

For the year ended December 31, 2011, we generated $103.6 million of revenue, $37.4 million of net income and $60.0 million of Adjusted EBITDA. These amounts reflect only two months of operations from our Grand River system, which we acquired in October 2011. Please read "—Our Assets—Grand River System." For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated in accordance with GAAP, please read "Selected Historical Financial and Operating Data—Non-GAAP Financial Measure."

Our Assets and Areas of Operation

The following table provides information regarding our assets by gathering system as of May 31, 2012, unless otherwise noted.

Gathering System	Formation(s) Served

Grand River	Mesaverde, Mancos and Niobrara	276	1,720	(2)	97,500	230,000	2,104	885	593
DFW Midstream	Barnett	110	310		50,100	100,000	463	410	315

Total		386	2,030		147,600	330,000	2,567	1,295	908

(1): As of the quarter ended March 31, 2012.
(2): Excludes wells connected to nine central receipt points that represent an aggregate average throughput of 250 MMcf/d.

Grand River System

In October 2011, we acquired certain natural gas gathering pipeline, dehydration and compression assets in the Piceance Basin of western Colorado, which we refer to as the Grand River system, from Encana for $590 million. The Grand River system comprises approximately 276 miles of pipeline and 97,500 horsepower of compression and is primarily located in Garfield County, Colorado, the largest natural gas producing county in Colorado. All of the natural gas gathered on the Grand River system is discharged to Enterprise Products Partners L.P.'s pipeline serving its 1.7 Bcf/d processing facility located in Meeker, Colorado. For the quarter ended March 31, 2012, the Grand River system gathered an average of approximately 593 MMcf/d from five producers, including Encana as the anchor customer.

Grand River system also gathers natural gas produced from our customers' wells targeting the deeper Mancos and Niobrara Shale formations, which have higher initial production rates and lower Btu gas content than Mesaverde wells. Over the last two years, our customers have completed numerous horizontal wells targeting the emerging Mancos and Niobrara Shale formations. Based on our customers' current drilling expectations, we anticipate the majority of our near-term throughput on the Grand River system will continue to be comprised of Mesaverde formation production.

We intend to expand the Grand River system by connecting additional pad sites within our AMIs, adding new customers and acquiring nearby gathering systems. We expect that, to the extent natural gas prices increase from current levels, our customers will accelerate drilling activities targeting the Mancos and Niobrara shale formations, which will provide us with an opportunity to construct a new medium pressure pipeline system to gather the resulting production and increase throughput on the Grand River system.

DFW Midstream System

In September 2009, we acquired approximately 17 miles of pipeline and 2,500 horsepower of electric-drive compression in north-central Texas, which we refer to as the DFW Midstream system, from Energy Future Holdings and Chesapeake. Since the initial acquisition, we have expanded the DFW Midstream system by adding approximately 93 miles of pipeline to connect 62 of 73 currently identified pad sites and installing an incremental 47,600 horsepower of electric-drive compression. The DFW Midstream system currently has five primary interconnections with third-party, intrastate pipelines that enable us to connect our customers, directly or indirectly, with the major natural gas market hubs of Waha, Carthage, and Katy in Texas, and Perryville and Henry Hub in Louisiana. For the quarter ended March 31, 2012, the DFW Midstream system gathered an average of approximately 315 MMcf/d from six producers.

Our DFW Midstream system benefits from its location within the primarily urban environment of southeastern Tarrant County, Texas, which resides within the Fort Worth Basin and includes the Barnett Shale formation. This area is commonly referred to as the core of the Barnett Shale and, according to the Texas Railroad Commission, contains the most prolific wells drilled in the Barnett Shale to date based on peak month daily average production rates. Construction of the DFW Midstream system is substantially complete and enables our customers to efficiently produce natural gas by utilizing horizontal drilling techniques throughout the vast majority of our AMIs from pad sites already connected to the DFW Midstream system. Given the urban nature of our area of operations, in what we consider to be the "core of the core" of the Barnett Shale, we expect that the majority of future natural gas drilling in this area will occur from these existing connected pad sites, which should enable us to increase throughput and cash flows with minimal additional capital expenditures.

Recent Trends

Since reaching a high of $13.58 per MMBtu in 2008, the prompt-month NYMEX price of natural gas has declined to a price of $2.42 per MMBtu as of May 31, 2012 due in large part to the significant increase in natural gas supply driven by drilling activity in unconventional resource plays (primarily shale formations and to a lesser extent coalbeds) combined with warm winter weather and reduced economic activity. As a result of this historically low natural gas price environment, some natural gas producers have cut back or suspended their drilling operations in certain "dry gas" regions where the economics of natural gas production are less favorable. Dry gas regions contain natural gas reserves that are primarily comprised of methane as compared to liquids-rich regions that contain NGLs in addition to methane. Drilling activities focused in liquids-rich regions have continued and, in some cases, have increased, as the higher Btu content associated with NGL production enhances overall drilling economics, even in a low natural gas price environment. We have exposure to both liquids-rich

and dry gas regions, and we believe our gathering systems are well positioned to capture additional volumes from increased producer activity in the future.

In the Piceance Basin, our Grand River system benefits from its exposure to liquids-rich gas production from the Mesaverde formation. The attractive economics associated with the production from this formation, combined with our minimum volume commitments from major producers in the area, provide us with stable cash flows and visible growth in the future. In addition, certain of our customers have joint venture agreements in place that provide for the development of portions of the Piceance Basin in our AMIs utilizing third-party funds. We believe the drilling activity from these partnerships will benefit our Grand River system. The Grand River system also serves the emerging Mancos and Niobrara formations, which we expect will become more active to the extent that natural gas prices increase.

Our DFW Midstream system benefits from its AMIs that cover the most prolific dry gas area of the Barnett Shale. We believe that this area offers our customers a compelling opportunity to maximize drilling economics due to the high estimated ultimate recovery of natural gas per well and relatively low drilling costs when compared to other dry gas resource basins. While recent market prices for natural gas have resulted in reduced drilling activity in the Barnett Shale, there remains a significant number of wells in various stages of completion in our AMIs that have already been connected to pad sites on the DFW Midstream system. These wells represent an opportunity to increase throughput on the DFW Midstream system at minimal incremental capital costs. In addition, because of the urban environment in which the DFW Midstream system is located, we expect that this area will continue to be developed by our customers using a high density pad site drilling strategy that is designed to support multiple wells from a single location. Instead of constructing pipelines to multiple wells, we connect to an individual pad site, some of which can accommodate up to 30 wells, and gather all of the natural gas produced at that site, thus minimizing our future capital expenditures. This pad site strategy substantially increases the efficiency of both the producers' drilling activities as well as our gathering activities and economics.

Business Strategies

Our principal business strategy is to increase the amount of cash distributions we make to our unitholders over time. Our plan for executing this strategy includes the following key components:

•: Increasing capacity of and throughput volumes on our existing systems. We intend to continue to focus our commercial efforts on increasing the capacity of and the throughput volumes on our systems from existing and new customers. The strategic location of our assets, along with our AMIs with several of the largest producers in our areas of operation, gives us the ability to gather incremental volumes at a lower capital cost as a result of the high-density pad site drilling strategy utilized by our customers in our areas of operation.
•: Capitalizing on organic growth opportunities. Our existing gathering systems provide us with significant organic expansion opportunities. We intend to leverage our management team's expertise in constructing, developing and optimizing our assets in order to extend our geographic reach, diversify our customer base, increase the number of our natural gas receipt points and maximize volume throughput.
•: 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 services under fee-based arrangements. Our gas gathering agreements include AMIs and minimum volume commitments, which promote cash flow visibility and stability and limit our direct exposure to commodity price volatility.
•: Partnering with large natural gas producers to provide midstream services for their development projects in high-growth, unconventional resource plays. We pursue opportunities to partner with

established producers in unconventional resource basins to develop new infrastructure that we believe will complement our existing midstream assets or enhance our overall business by facilitating our entry into new basins. These opportunities generally consist of strategic acreage positions in unconventional resource plays that are well positioned for accelerated production growth but have minimal existing midstream energy infrastructure to support such growth. We have been successful with this strategy and will continue to pursue similar opportunities that utilize our management team's experience in constructing, developing and operating large scale midstream infrastructure.

•: Diversifying our asset base by exploring acquisition and development opportunities in various geographical areas and other sectors of the midstream industry. While our natural gas gathering operations in the Piceance Basin and Barnett Shale currently represent our core business, we intend to diversify our business into other sectors of the midstream industry that handle other hydrocarbon commodities (through both greenfield development projects and acquisitions) and into other geographic regions.

Competitive Strengths

We believe that we will be able to execute the components of our principal business strategy successfully because of the following competitive strengths:

•: Strategically located assets in core areas of prolific unconventional basins supported by existing partnerships with large producers to provide midstream services for their development projects. We believe our assets will continue to be utilized in various commodity price cycles. Our midstream energy infrastructure assets are strategically positioned within the core areas of two prolific plays. The Grand River system and the DFW Midstream system serve formations characterized by prolific production profiles and low drilling and completion costs. In addition, our Piceance Basin customers are exploring new plays within our Grand River AMIs that, if successful, will offer us opportunities for further organic growth.
•: Fee-based revenues underpinned by long-term contracts. A substantial majority of our revenue for the year ended December 31, 2011 was generated under long-term, fee-based gas gathering agreements. Our gas gathering agreements with our Piceance Basin customers have AMIs covering approximately 230,000 acres and minimum volume commitments of approximately 2.1 Tcf through 2026. Our gas gathering agreements with our Barnett Shale customers have AMIs covering approximately 100,000 acres and minimum volume commitments of approximately 463 Bcf through 2020.
•: Capital structure and financial flexibility. At the closing of this offering, we expect to have approximately $ million of borrowing capacity available to us under our amended and restated revolving credit facility. We believe our borrowing capacity and our ability to access private and public debt and equity capital will provide us with the requisite financial flexibility to execute our business strategy.
•: Experienced management team with proven record of asset acquisition, construction, development, operation and integration expertise. Our executive management team has an average of 16 years of energy experience and a proven track record of identifying and consummating significant acquisitions in addition to partnering with major producers to construct and develop midstream infrastructure. We employ engineering, construction and operations teams that have significant experience in designing, constructing and operating large midstream energy projects.
•: Relationships with large and committed financial sponsors. Our sponsors, Energy Capital Partners and GE Energy Financial Services, are experienced energy investors with proven track records of making substantial, long-term investments in high-quality midstream energy assets. Energy Capital Partners has indicated that it intends to use us as its primary platform for the

acquisition, construction and development of future midstream infrastructure assets; however, it is not obligated to do so. While there are no assurances that we will benefit from our relationship with our sponsors, we believe our relationship with both of our sponsors will be a competitive advantage, as they both bring not only significant financial and management experience, but also numerous relationships throughout the energy industry that we believe will benefit us as we seek to grow our business.

Our Sponsors

We were formed in 2009 by members of management and Energy Capital Partners, which together with its affiliated funds, is a private equity firm with over $7.0 billion in capital commitments that is focused on investing in North America's energy infrastructure. Energy Capital Partners has significant energy and financial expertise to complement its investment in us. To date, Energy Capital Partners has formed 21 investment platforms across its funds with investments in the power generation, electric transmission, midstream natural gas and renewable sectors of the energy industry. In August 2011, Energy Capital Partners sold an interest in Summit Investments to GE Energy Financial Services. GE Energy Financial Services invests globally in essential, long-lived and capital-intensive energy assets. To date, GE Energy Financial Services has invested over $20 billion in energy investments worldwide, of which approximately $2.4 billion has been committed to midstream-related portfolio companies.

Risk Factors

An investment in our common units involves risks associated with our business, regulatory and legal matters, our limited partnership structure and the tax characteristics of our common units. The following list of risk factors should be read carefully in conjunction with the risks under the caption "Risk Factors" immediately following this Summary, beginning on page 20.

Risks Related to our Business

•: We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution or any distribution to holders of our common and subordinated units.
•: On a historical as adjusted basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our units for the year ended December 31, 2011 and for the twelve months ended March 31, 2012.
•: The assumptions underlying the forecast of cash available for distribution that we include in "Our Cash Distribution Policy and Restrictions on Distributions" are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.
•: We depend on a relatively small number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, or the curtailment of production by, any one or more of these customers could materially adversely affect our revenues, cash flow and ability to make distributions to our unitholders.
•: We gather natural gas from the Piceance Basin and the Barnett Shale. Due to our lack of industry and geographic diversification, adverse developments in our existing areas of operation could materially adversely impact our financial condition, results of operations and cash flows and reduce our ability to make cash distributions to our unitholders.
•: Significant prolonged changes in natural gas prices could affect supply and demand, reducing throughput on our systems and materially adversely affecting our revenues and cash available to make distributions to you over the long-term.

•: Because of the natural decline in production from existing wells in our areas of operation, our success depends in part on our customers replacing declining production and also on our ability to maintain levels of throughput on our systems. Any decrease in the volumes of natural gas that we gather could materially adversely affect our business and operating results.
•: Our gas gathering agreements contain provisions that can reduce the cash flow stability that the agreements were designed to achieve.

Risks Inherent in an Investment in Us

•: Summit Investments owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations and has limited duties to us and our unitholders. Summit Investments and our general partner have conflicts of interest with us and they may favor their own interests to the detriment of us and our unitholders.
•: Our sponsors are not limited in their ability to compete with us and are not obligated to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could adversely affect our results of operations and cash available for distribution to our unitholders.
•: There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the market price of our common units may fluctuate significantly, and you could lose all or part of your investment.
•: Our partnership agreement limits the liabilities of our general partner and the rights of our unitholders with respect to actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
•: Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
•: Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

Tax Risks

•: Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service (IRS) were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.
•: If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.
•: 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.
•: Our unitholders' share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

Formation Transactions and Partnership Structure

In connection with the closing of this offering, the following transactions will occur:

•: Summit Investments will convey an interest in Summit Midstream Holdings, LLC, or Summit Holdings, to our general partner as a capital contribution;

•

our general partner will convey its interest in Summit Holdings to us in exchange for (i) a continuation of its 2% general partner interest in us, represented by general partner units, and (ii) our incentive distribution rights, or IDRs;

•

Summit Investments will convey its remaining interest in Summit Holdings to us in exchange for (i) common units, representing a % limited partner interest in us, (ii) subordinated units, representing a �� % limited partner interest in us, and (iii) the right to receive $ in cash as reimbursement for certain capital expenditures made with respect to the contributed assets;

•

we will issue common units to the public, representing a % limited partner interest in us; and

•

we will use the net proceeds from the offering to:

•: repay $ million outstanding under our revolving credit facility;
•: make a cash distribution to Summit Investments of $ million in order to reimburse Summit Investments for certain capital expenditures it incurred with respect to assets it contributed to us;
•: retain approximately $ million for general partnership purposes; and
•: pay estimated offering expenses of $ million.

Ownership of Summit Midstream Partners, LP

The diagram below illustrates our organization and ownership after giving effect to this offering and the related recapitalization transactions and assumes that the underwriters' option to purchase additional common units is not exercised.


Public Common Units		%
Summit Investments Units:
Common Units		%
Subordinated Units		%
General Partner Interest	2.0	%

Total	100.0	%

(1): Does not reflect outstanding Class B membership units indirectly owned by certain current and former management and employees of DFW Midstream Services LLC.

Our Management

We are managed and operated by the board of directors and executive officers of Summit GP, our general partner. Summit Investments, which is controlled by Energy Capital Partners and GE Energy Financial Services, is the sole owner of our general partner and has the right to appoint the entire board of directors of our general partner, including our independent directors. Unlike shareholders in a publicly traded corporation, our unitholders will not be entitled to elect our general partner or the board of directors of our general partner. For more information about the directors and executive officers of our general partner, please read "Management—Directors and Executive Officers" beginning on page 146.

In order to maintain operational flexibility, our operations will be conducted through, and our operating assets will be owned by, various operating subsidiaries. However, neither we nor our subsidiaries have any employees. Our general partner has the sole responsibility for providing the personnel necessary to conduct our operations, whether through directly hiring employees or by obtaining the services of personnel employed by others. All of the personnel that will conduct our business immediately following the closing of this offering will be employed by our general partner and its affiliates, but we sometimes refer to these individuals in this prospectus as our employees.

Following the closing of this offering, our general partner and its affiliates will not receive any management fee or other compensation in connection with our general partner's management of our business, but will be reimbursed for expenses incurred on our behalf. These expenses include the costs of employee and director compensation and benefits properly allocable to us, and all other expenses necessary or appropriate for the conduct of our business and allocable to us. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 2100 McKinney Avenue, Suite 1250, Dallas, Texas 75201 and our telephone number is (214) 242-1955. Our website is located at and will be activated in connection with the closing of this offering. We expect to make available our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as the SEC, free of charge through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

Summary of Conflicts of Interest and Duties

General

Our general partner has a duty to manage us in a manner it believes is in the best interests of our partnership and our unitholders. However, the officers and directors of our general partner also have a duty to manage the business of our general partner in a manner it believes is in the best interests of its owners, including Energy Capital Partners and GE Energy Financial Services. Certain of the directors of our general partner are also officers of Energy Capital Partners and GE Energy Financial Services. As a result of these relationships, conflicts of interest may arise in the future between us and holders of our common units, on the one hand, and Energy Capital Partners, GE Energy Financial Services and our general partner, on the other hand. For example, our general partner will be entitled to make determinations that affect the amount of cash distributions we make to the holders of common units, which in turn has an effect on whether our general partner receives incentive cash distributions.

Partnership Agreement Replacement of Fiduciary Duties

Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner to us and our unitholders with contractual standards governing the duties of the general partner to us and our unitholders and the methods of resolving conflicts of interest. The effect of these provisions is to limit the liability of our general partner and the rights of our unitholders with respect to actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement and, pursuant to the terms of our partnership agreement, each holder of common units consents to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under applicable state law.

Energy Capital Partners and GE Energy Financial Services May Compete Against Us

Although our relationships with Energy Capital Partners and GE Energy Financial Services are valuable assets to us, they are also a source of potential conflict. For example, our partnership agreement does not prohibit Energy Capital Partners, GE Energy Financial Services or their respective affiliates, other than our general partner, from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Energy Capital Partners and GE Energy Financial Services may acquire, construct or dispose of additional midstream or other assets in the future, without any obligation to offer us the opportunity to acquire or construct any of those assets. Even though Energy Capital Partners has indicated to us that it intends for us to be its primary platform for owning midstream energy infrastructure assets, it has no obligation to follow that strategy.

For a more detailed description of the conflicts of interest and the duties of our general partner, please read "Conflicts of Interest and Duties."

Implications of Being an Emerging Growth Company

As a company with less than $1.0 billion in revenue during its last fiscal year, we qualify as an "emerging growth company" as defined in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act. An emerging growth company may take advantage of specified reduced reporting and other regulatory requirements for up to five years that are otherwise applicable generally to public companies. These provisions include:

•: a requirement to present only two years of audited financial statements and only two years of related Management's Discussion and Analysis;
•: exemption from the auditor attestation requirement on the effectiveness of our system of internal control over financial reporting;
•: exemption from the adoption of new or revised financial accounting standards until they would apply to private companies;
•: exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor's report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; and
•: reduced disclosure about executive compensation arrangements.

We will cease to be an emerging growth company if we have more than $1.0 billion in annual revenues, have more than $700 million in market value of our limited partner interests held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

We have elected to take advantage of the applicable JOBS Act provisions, except for the following:

•: we have elected to present three years of audited financial statements and three years of related Management's Discussion and Analysis rather than only two years; and
•: we have elected to opt out of the exemption that allows emerging growth companies to extend the transition period for complying with new or revised financial accounting standards (this election is irrevocable).

Accordingly, the information that we provide you may be different than what you may receive from other public companies in which you hold equity interests.

The Offering


Common units offered to the public		common units.
		common units if the underwriters exercise in full their option to purchase additional common units.
Units outstanding after this offering		common units and subordinated units, each representing a 49.0% limited partner interest in us. Our general partner will own general partner units, representing a 2.0% general partner interest in us.
Use of proceeds		We intend to use the net proceeds from this offering of approximately $ million, after deducting underwriting discounts, commissions and a structuring fee, to:
		• repay $ million of indebtedness outstanding under our revolving credit facility;
		• make a cash distribution to Summit Investments of $ million in order to reimburse Summit Investments for certain capital expenditures it incurred with respect to assets it contributed to us; and
		• pay estimated offering expenses of $ million.
		We intend to retain the remainder of the net proceeds for general partnership purposes.
		If the underwriters exercise their option to purchase additional common units, we will use the net proceeds from that exercise to redeem from Summit Investments the number of common units issued upon such exercise.
Cash distributions		We intend to pay a minimum quarterly distribution of $ per unit ($ per unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We refer to this cash as "available cash." Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption "Our Cash Distribution Policy and Restrictions on Distributions." We will adjust the minimum quarterly distribution payable for the period from the closing of this offering through September 30, 2012, based on the length of that period.
		Our partnership agreement requires that we distribute all of our available cash each quarter in the following manner:
		• first, 98.0% to the holders of common units and 2.0% to our general partner, until each common unit has received the minimum quarterly distribution of $ plus any arrearages from prior quarters;


		• second, 98.0% to the holders of subordinated units and 2.0% to our general partner, until each subordinated unit has received the minimum quarterly distribution of $ ; and
		• third, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unit has received a distribution of $ .
		If cash distributions to our unitholders exceed $ per unit in any quarter, our general partner will receive, in addition to distributions on its 2.0% general partner interest, increasing percentages, up to 48.0%, of the cash we distribute in excess of that amount. We refer to these distributions as "incentive distributions." In certain circumstances, our general partner, as the initial holder of our incentive distribution rights, will have the right to reset the target distribution levels to higher levels based on our cash distributions at the time of the exercise of this reset election. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions."
		The amount of cash available for distribution that we generated during the year ended December 31, 2011 would have been sufficient to pay the full minimum quarterly distribution on all common units but only a cash distribution of $ per quarter ($ on an annualized basis), or approximately % of the minimum quarterly distribution, on all of our subordinated units for that period. In addition, the amount of cash available for distribution that we generated during the twelve months ended March 31, 2012 would have been sufficient to pay the full minimum quarterly distribution on all common units but only a cash distribution of $ per quarter ($ on an annualized basis), or approximately % of the minimum quarterly distribution, on all of our subordinated units for that period. This shortfall in cash available for distribution is due primarily to our owning the Grand River system for only two months during the year ended December 31, 2011 and for only five months during the twelve months ended March 31, 2012.
		We believe that, based on our estimated cash available for distribution included under the caption "Our Cash Distribution Policy and Restrictions on Distributions," we will have sufficient cash available for distribution to pay the annualized minimum quarterly distribution of $ per unit on all common and subordinated units, as well as the corresponding distribution on our 2.0% general partner interest, for the twelve months ending June 30, 2013. However, we do not have a legal binding obligation to pay quarterly distributions at our minimum quarterly distribution rate or any other rate except as provided in our partnership agreement. There is no guarantee that we will distribute quarterly cash distributions to our unitholders in any quarter. Please read "Our Cash Distribution Policy and Restrictions on Distributions."


Subordinated units		Summit Investments will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.
Conversion of subordinated units		The subordination period will end on the first business day after we have earned and paid at least (1) $ (the minimum quarterly distribution on an annualized basis) on each outstanding common unit and subordinated unit and the corresponding distribution on the general partner's 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after , 2015 or (2) $ (150.0% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and the corresponding 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.
		The subordination period also will end upon the removal of the general partner other than for cause if no subordinated units or common units held by the holder(s) of subordinated units or their affiliates are voted in favor of that removal.
		When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and thereafter no common units will be entitled to arrearages.
Issuance of additional units		Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Please read "Units Eligible for Future Sale" and "The Partnership Agreement—Issuance of Additional Securities."


Limited voting rights		Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or its directors on an annual or continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66²/3% of the outstanding limited partner units voting together as a single class, including any limited partner units owned by our general partner and its affiliates, including Summit Investments. Upon the closing of this offering, Summit Investments will own an aggregate of % of our common and subordinated units (or % of our outstanding common and subordinated units if the underwriters exercise in full their option to purchase additional units). This will give Summit Investments the ability to prevent the involuntary removal of our general partner. Please read "The Partnership Agreement—Voting Rights."
Limited call right		If at any time our general partner and its affiliates own more than 80.0% of the outstanding common units, our general partner will have the right, but not the obligation, to purchase all of the remaining common units at a price that is not less than the then-current market price of the common units.
Estimated ratio of taxable income to distributions		We estimate that if you own the common units you purchase in this offering through the record date for distributions for the quarter ending , 2014, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $ per unit, we estimate that your average allocable federal taxable income per year will be no more than $ per unit. Please read "Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions" and "Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses."
Material federal income tax consequences		For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, or the U.S., please read "Material Federal Income Tax Consequences."
Exchange listing		We intend to apply to list our common units on the New York Stock Exchange, or NYSE, under the symbol "SMLP."

SUMMARY HISTORICAL FINANCIAL AND OPERATING DATA

The following table presents, as of the dates and for the periods indicated, the summary historical consolidated financial and operating data of our Predecessor. On September 3, 2009, we acquired a controlling interest in DFW Midstream Services LLC, which we refer to as our Initial Predecessor for the period prior to such date. We use the term Summit Midstream Predecessor to describe our Predecessor's operations after September 3, 2009. We acquired the Grand River system on October 27, 2011 and we have included its financial results in the financial statements of Summit Midstream Predecessor since the date of acquisition.

The summary historical consolidated financial data presented as of March 31, 2012 and for the three months ended March 31, 2012 and March 31, 2011 are derived from our unaudited historical condensed financial statements included elsewhere in this prospectus. The summary historical consolidated financial data presented as of December 31, 2011 and December 31, 2010 and for the period from September 3, 2009 to December 31, 2009, for the year ended December 31, 2011 and the year ended December 31, 2010 have been derived from the audited historical consolidated financial statements of Summit Midstream Predecessor included elsewhere in this prospectus. The summary historical balance sheet data as of December 31, 2009 are derived from the audited historical financial statement of Summit Midstream Predecessor that are not included in this prospectus. The summary historical financial data for the period from January 1, 2009 to September 3, 2009 are derived from the audited historical financial statements of our Initial Predecessor included elsewhere in this prospectus. We acquired our initial assets from Energy Future Holdings Corp. and Chesapeake effective as of September 3, 2009.

For a detailed discussion of the information presented in the following table, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations." The following table should also be read in conjunction with the historical audited and unaudited consolidated financial statements and related notes of our Predecessor included elsewhere in this prospectus. Among other things, those historical financial statements include more detailed information regarding the basis of presentation for the information below.

The following table presents the non-GAAP financial measures of EBITDA and Adjusted EBITDA, which we use in our business as measures of performance and liquidity. We define EBITDA as net income:

•

Plus:

•: interest expense;
•: income tax expense; and
•: depreciation and amortization expense.

•

Less:

•: interest income; and
•: income tax benefit.

We define Adjusted EBITDA as EBITDA:

•

Plus:

•: non-cash equity compensation; and
•: deferred revenue related to MVCs.

For a reconciliation to our most directly comparable financial measures calculated and presented in accordance with GAAP, please read "Selected Historical Financial and Operating Data—Non-GAAP Financial Measure" on page 93.

	Summit Midstream Predecessor															Initial Predecessor

	Three Months Ended March 31,						Year Ended December 31,									Initial Predecessor
	Three Months Ended March 31,						Year Ended December 31,						Period from September 3, 2009 to December 31, 2009			Period from January 1, 2009 to September 3, 2009
	2012			2011			2011			2010			Period from September 3, 2009 to December 31, 2009			Period from January 1, 2009 to September 3, 2009
	(in thousands, except for volume and price amounts)
Statement of Operations Data:
Revenue:
Gathering services and other fees	$	31,918		$	17,128		$	91,421		$	29,358		$	1,714		$	1,910
Natural gas and condensate sales		3,731			2,117			12,439			2,533			—			—
Amortization of favorable and unfavorable contracts(1)		134			(70	)		(308	)		(215	)		19			—

Total revenue	$	35,783		$	19,175		$	103,552		$	31,676		$	1,733		$	1,910
Costs and expenses:
Operations and maintenance		10,989			6,148			29,855			9,503			1,147			1,010
General and administrative		4,412			3,843			17,476			10,035			2,939			600
Transaction costs		193			—			3,166			—			3,921			—
Depreciation and amortization		8,290			1,605			11,915			3,874			343			882

Total costs and expenses		23,884			11,596			62,412			23,412			8,350			2,492

Interest (expense) income, net		(4,173	)		5			(3,042	)		32			18			(247	)
Income tax expense		(139	)		(73	)		(695	)		(124	)		(7	)		(8	)

Net income (loss)	$	7,587		$	7,511		$	37,403		$	8,172		$	(6,606	)	$	(837	)

Pro forma earnings per common unit(2)
Pro forma weighted average common units outstanding(2)
Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	16,605		$	8,855		$	39,942		$	9,553		$	(6,232	)	$	595
Investing activities		(20,577	)		(19,606	)		(667,710	)		(153,719	)		(64,415	)		(40,777	)
Financing activities		(579	)		8,000			633,809			114,132			110,102			40,182
Balance Sheet Data (at period end):
Cash and cash equivalents	$	10,911					$	15,462		$	9,421		$	39,455
Trade accounts receivable		30,997						27,476			10,238			1,373
Property, plant, and equipment, net		652,732						642,552			277,765			140,704
Total assets		1,032,164						1,026,498			340,095			215,982
Total debt(3)		353,940						349,893			—			—
Other Financial Data:
EBITDA(4)	$	20,055		$	9,254		$	53,363		$	12,353		$	(6,293	)	$	300
Adjusted EBITDA(4)	$	23,699		$	10,468		$	56,803		$	12,353		$	(6,293	)	$	300
Capital expenditures		20,577			19,606			78,248			153,719			19,519			40,777
Acquisition expenditures(5)		—			—			589,462			—			44,896			—
Operating data:
Average throughput (MMcf/d)		908.4			285.2			428.0			134.3			15.4			15.7

(1): The amortization of favorable and unfavorable contracts relates to gas gathering agreements that were deemed to be above or below market on September 3, 2009, the date of the acquisition of the DFW Midstream system, which are amortized 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): The pro forma earnings per common unit gives effect to the recapitalization transactions as of December 31, 2011 and March 31, 2012 and the additional number of common units issued in this offering (at an assumed offering price of $ per unit) necessary to pay the portion of the distribution to Summit Investments described in "Use of Proceeds" that will be funded from the proceeds of this offering that exceeds net income for the year ended December 31, 2011 and the three months ended March 31, 2012. For a description of the calculation of pro forma earnings attributable to common and subordinated units, please read Note 1 to our audited consolidated financial statements and Note 1 to our unaudited consolidated financial statements included elsewhere in this prospectus. For a reconciliation of historical weighted average common units used in the computation of limited partners' net income (loss) per common unit and pro forma weighted average common and subordinated units outstanding, please read Note 1 to our audited consolidated financial statements and Note 1 to our unaudited condensed consolidated financial statements included elsewhere in this prospectus.
(3): Includes $202.9 million and $206.9 million of debt outstanding under our promissory notes payable to our sponsors at December 31, 2011 and March 31, 2012. On July 2, 2012, the outstanding balance under the notes was paid in full.

(4): EBITDA and Adjusted EBITDA for the three months ended March 31, 2012 and for the year ended December 31, 2011 include $0.2 million and $3.2 million, respectively, in transaction costs related to our acquisition of Grand River. EBITDA and Adjusted EBITDA for the year ended December 31, 2010 include $1.8 million in settlement expenses related to a dispute with a contractor at the DFW Midstream system. EBITDA and Adjusted EBITDA for the 2009 Summit Midstream Predecessor Period include transaction costs of $3.9 million primarily related to the acquisition of the DFW Midstream system in September 2009. These unusual and non-recurring expenses were included in the calculations of EBITDA and Adjusted EBITDA and were settled in cash.
(5): Reflects the acquisition of certain assets of the DFW Midstream system from Chesapeake in September 2009 and the acquisition of the Grand River System in October 2011.

RISK FACTORS

Limited partner units are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. We urge you to carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

If any of the following risks were to materialize, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment in us.

Risks Related to our Business

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution or any distribution to holders of our common and subordinated units.

In order to pay the minimum quarterly distribution of $ per unit per quarter, or $ per unit on an annualized basis, we will require available cash of approximately $ million per quarter, or $ million per year, based on the number of common and subordinated units to be outstanding immediately after completion of this offering. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

•: the volume of natural gas we gather and compress;
•: the level of production of natural gas from wells connected to our gathering systems, which is dependent in part on the demand for, and the market prices of, natural gas and natural gas liquids, or NGLs;
•: damage to pipelines, facilities, related equipment and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters 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, our existing contracts, our operating costs or our operating flexibility; and
•: prevailing economic and market conditions.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

•: the level and timing of capital expenditures we make;

•: the level of our operating and general and administrative expenses, including reimbursements to our general partner for services provided to us;
•: the cost of acquisitions, if any;
•: our debt service requirements and other liabilities;
•: fluctuations in our working capital needs;
•: our ability to borrow funds and access capital markets;
•: restrictions contained in our debt agreements;
•: the amount of cash reserves established by our general partner; and
•: other business risks affecting our cash levels.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read "Our Cash Distribution Policy and Restrictions on Distributions."

On a historical as adjusted basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our units for the year ended December 31, 2011 and for the twelve months ended March 31, 2012.

We must generate approximately $ million of available cash to pay the minimum quarterly distribution for four quarters on all of our common and subordinated units that will be outstanding immediately following this offering, as well as the corresponding distribution on our 2.0% general partner interest. The amount of cash available for distribution that we generated during the year ended December 31, 2011 would have been sufficient to pay the full minimum quarterly distribution on all common units but only a cash distribution of $ per quarter ($ on an annualized basis), or approximately % of the minimum quarterly distribution, on all of our subordinated units for that period. In addition, the amount of cash available for distribution that we generated during the twelve months ended March 31, 2012 would have been sufficient to pay the full minimum quarterly distribution on all common units but only a cash distribution of $ per quarter ($ on an annualized basis), or approximately % of the minimum quarterly distribution, on all of our subordinated units for that period. For a calculation of our ability to make cash distributions to our unitholders based on our historical as adjusted results, please read "Our Cash Distribution Policy and Restrictions on Distributions."

The assumptions underlying the forecast of cash available for distribution that we include in "Our Cash Distribution Policy and Restrictions on Distributions" are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

The forecast of cash available for distribution set forth in "Our Cash Distribution Policy and Restrictions on Distributions" includes our forecasted results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending June 30, 2013. We estimate that our total cash available for distribution for the twelve months ending June 30, 2013 will be approximately $85.9 million, as compared to approximately $39.8 million for the year ended December 31, 2011 and approximately $49.3 million for the twelve months ended March 31, 2012 on a historical as adjusted basis. The significant expected increase in cash available for distribution is primarily attributable to the inclusion of the Grand River system for the entire forecast period as compared to just two months for the year ended December 31, 2011 and for only five months during the twelve months ended March 31, 2012. To the extent that volumes on either the Grand River system or the DFW Midstream system are lower than we project, our revenues during the forecast period will be adversely affected. If the actual volume of natural gas we gather on our systems for the twelve months ending June 30, 2013 is 10%

lower than our forecast, we expect we would have sufficient cash available to pay the full distribution to holders of our common units and only % of the aggregate annualized minimum quarterly distribution to the holders of our subordinated units. The financial forecast has been prepared by management, and we have not received an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks, including risks that expansion projects do not result in an increase in gathered volumes, and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common or subordinated units, in which event the market price of our common units may decline materially.

We depend on a relatively small number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, or the curtailment of production by, any one or more of these customers could materially adversely affect our revenues, cash flow and ability to make distributions to our unitholders.

A significant percentage of our revenue is attributable to a relatively small number of customers. Chesapeake, Carrizo Oil & Gas, Inc., or Carrizo, and TOTAL accounted for approximately 34%, 17% and 10%, respectively, of our revenue for the year ended December 31, 2011. Encana, Carrizo and Chesapeake accounted for approximately 31%, 18% and 16%, respectively, of our revenue for the three months ended March 31, 2012. If our customers curtail or reduce production in our areas of operation it could reduce throughput on our system and, therefore, adversely affect our revenues, cash flow and ability to make distributions to our unitholders. For example, in January 2012 Chesapeake announced its intent to decrease drilling activity in predominantly dry gas areas such as the Barnett Shale region as well as reduce its dry gas production by up to 500 MMcf/d. For the three months ended March 31, 2012, average daily throughput on the DFW Midstream system declined approximately 17.5% compared to the three months ended December 31, 2011 primarily as a result of Chesapeake's publicly announced reduction in production. Please read "—Our gas gathering agreements contain provisions that can reduce the cash flow stability that the agreements were designed to achieve."

Some of our customers may have material financial and liquidity issues or may, as a result of operational incidents or other events, be disproportionately affected as compared to larger, better-capitalized companies. Any material nonpayment or nonperformance by any of our key customers could have a material adverse effect on our revenue and cash flows and our ability to make cash distributions to our unitholders. In any of these situations, our revenue and cash flows and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our revenue. In addition, if any one or more of our gas gathering agreements that account for 25% or more of our revenues are terminated, and such termination is reasonably expected to have a Material Adverse Effect (as defined in our amended and restated revolving credit facility), and a replacement agreement is not obtained within 30 days, this would constitute an event of default under our amended and restated revolving credit facility and our lenders would be able to accelerate payment of the debt outstanding thereunder.

We gather natural gas from the Piceance Basin and the Barnett Shale. Due to our lack of industry and geographic diversification, adverse developments in our existing areas of operation could materially adversely impact our financial condition, results of operations and cash flows and reduce our ability to make cash distributions to our unitholders.

Our operations are focused on natural gas gathering and compression services. Our assets are located exclusively in the Piceance Basin in western Colorado and the Barnett Shale region in north-central Texas and we intend to focus our future capital expenditures largely on developing our business

in these areas. As a result, our financial condition, results of operations and cash flows depend upon the demand for our services in these regions. Due to our lack of industrial and geographic diversity, adverse developments in our current segment of the midstream industry or our existing areas of operation could have a significantly greater impact on our financial condition, results of operations and cash flows than if our operations were more diversified. For example, a significant portion of the gas we gather in the Piceance Basin and the Barnett Shale is dry gas. Due to recent declines in natural gas prices, several of our customers have substantially reduced their dry gas production in these regions and announced their intent to reduce capital expenditures for dry gas drilling activities.

A significant portion of our operations are concentrated in the Barnett Shale region, which could disproportionately expose us to operational and regulatory risk in that area. The location of the Barnett Shale in the Dallas-Fort Worth, Texas metropolitan area poses unique challenges associated with drilling for natural gas in urban and suburban communities. The DFW Midstream system is within the city limits of various municipalities in that region, including Arlington, Texas. State and local regulations regarding the operation of drilling rigs limit the number of potential new drilling sites that can be used for infill drilling programs, which has led producers to pursue a high density pad site drilling strategy. Furthermore, the process of obtaining permits for constructing additional gathering lines to deliver our customers' natural gas to market may be more time consuming and costly than in more rural areas. In addition, we may experience a higher rate of litigation or increased insurance and other costs related to our operations or facilities in such highly populated areas.

Significant prolonged changes in natural gas prices could affect supply and demand, reducing throughput on our systems and materially adversely affecting our revenues and cash available to make distributions to you over the long-term.

Lower natural gas prices over the long-term could result in a decline in the production of natural gas resulting in reduced throughput on our systems. Recently, the price of natural gas has been at historically low levels, with the prompt month NYMEX natural gas futures price reaching $2.42 per MMBtu as of May 31, 2012, compared to a high of $13.58 per MMBtu in July 2008. The lower price of natural gas is due in part to increased production, especially from unconventional sources, such as natural gas shale plays, high levels of natural gas in storage and the effects of the economic downturn starting in 2008. According to the U.S. Energy Information Administration, the EIA, average annual natural gas production in the United States increased 14.1% from 55.2 Bcf/d to 63.0 Bcf/d from 2008 to 2011. Furthermore, the amount of natural gas in storage in the continental United States has increased from approximately 2.2 Tcf as of June 3, 2011 to approximately 2.9 Tcf as of June 1, 2012, due to the unseasonably warm winter of 2011/2012 and to the decisions of many producers to store natural gas in the expectation of higher prices in the future. In response to lower natural gas prices, the number of natural gas drilling rigs has declined from approximately 1,403 as of December 31, 2008 to approximately 515 as of May 31, 2012 according to Smith Bits (a unit of Schlumberger Limited), as a number of producers have curtailed their exploration and production activities. We believe that over the short term, until the supply overhang has been reduced and the economy sees more robust growth, natural gas pricing is likely to be constrained.

The decline in natural gas prices has had a negative impact on exploration, development and production activity in our areas of operation. If natural gas prices remain depressed or decrease further, it could cause sustained reductions in exploration or production activity in our areas of operation and result in a further reduction in throughput on our systems, which could have a material adverse effect on our business, financial condition, results of operations and ability to make 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 on our systems. As a result, significant prolonged changes

in natural gas prices could have a material adverse effect on our business, financial condition, results of operations and ability to make 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 our customers replacing declining production and also on our ability to maintain levels of throughput on our systems. Any decrease in the volumes of natural gas that we gather could materially adversely affect our business and operating results.

The natural gas volumes that support our business depend on the level of production from natural gas wells connected to our systems, the production from which may be less than expected and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our systems, we must obtain new sources of natural gas. The primary factors affecting our ability to obtain non-dedicated sources of natural gas include (i) the level of successful drilling activity in our areas of operation and (ii) our ability to compete for volumes from successful new wells.

We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling and production decisions, which are affected by, among other things:

•: 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 hydraulic fracturing; and
•: the availability of drilling rigs and other costs of production and equipment.

Fluctuations in energy prices can also greatly affect the development of new oil and natural gas reserves. Drilling and production activity generally decreases as natural gas prices decrease. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include worldwide economic conditions; weather conditions and seasonal trends; the levels of domestic production and consumer demand; the availability of imported liquefied natural gas, or LNG; the 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 to develop those reserves. Recent declines in natural gas prices have had a negative impact on exploration, development and production activity and, if sustained, could lead to further decreases in such activity. Sustained reductions in exploration or production activity in our areas of operation could lead to further reductions in the utilization of our systems, which could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

In addition, it may be more difficult to maintain or increase the current volumes on our gathering systems, as several of the formations in the unconventional resource plays in which we operate

generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Should we determine that the economics of our gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, revenues associated with these assets will decline over time. In addition to capital expenditures to support growth, the steeper production decline curves associated with unconventional resource plays may require us to incur higher maintenance capital expenditures over time, which will reduce our cash available for distribution from operating surplus.

Many of our operating costs are fixed and do not vary with our throughput. These costs may not decline ratably or at all should we experience a reduction in throughput, which would result in a decline in our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

Because of these and other factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, those reductions could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

If our customers do not increase the volumes of natural gas they provide to our gathering systems, our growth strategy and ability to increase cash distributions to our unitholders may be adversely affected.

If we are not successful in attracting new customers, our ability to increase the throughput on our gathering systems will be dependent on receiving increased volumes from our existing customers. Other than the scheduled increases in the minimum volume commitments provided for in our gas gathering agreements, our customers are not obligated to provide additional volumes to our systems, and they may determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. For example, in January 2012, Chesapeake announced its intent to decrease drilling activity in predominantly dry gas areas such as the Barnett Shale region and to reduce its total dry gas production by up to 500 MMcf/d. Similarly, in February 2012, Encana announced its intent to reduce its dry gas production to approximately 3.1 Bcf/d, a decrease of approximately 250 MMcf/d from 2011 levels. For the three months ended March 31, 2012, average daily throughput on the DFW Midstream system declined approximately 17.5% compared to the three months ended December 31, 2011, primarily as a result of Chesapeake's publicly announced reduction in production. Encana's public announcement has not impacted the volume on our Grand River system but may do so in the future. Any further reductions by Chesapeake or our other customers in our areas of operation could result in further reductions in throughput on our systems and adversely impact our ability to grow our operations and increase cash distributions to our unitholders.

Our gas gathering agreements contain provisions that can reduce the cash flow stability that the agreements were designed to achieve.

Our gas gathering agreements were designed to generate stable cash flows to us over the long term. The primary mechanism on which we rely to generate our stable cash flows is an annual minimum volume commitment, or MVC, from our customers. Under these annual MVCs, our customers agree to ship a minimum volume of natural gas on our gathering systems or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. In addition, the majority of our gas gathering agreements also include an aggregate MVC, which is a total amount of natural gas that the customer must transport on our gathering system (or an equivalent monetary amount) over the MVC term. If a customer's actual throughput volumes are less than its MVC for the applicable period, it must make a shortfall payment to us at the end of that contract month or year, as applicable. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped for the applicable period and the MVC for the applicable period,

multiplied by the applicable gathering fee. To the extent that a customer's actual throughput volumes are above or below its MVC for the applicable period, however, many of our GGAs contain provisions that can operate to reduce or delay the cash flows that we expect to receive from our MVCs. These provisions include the following:

•: To the extent that a customer's throughput volumes are less than its MVC for the applicable period and the customer makes a shortfall payment, it is entitled to an offset in one or more subsequent periods to the extent that its throughput volumes in subsequent periods exceed its MVC for those periods. In such a situation, we would not receive gathering fees on throughput in excess of a customer's monthly or annual MVC (depending on the terms of the specific gas gathering agreement) to the extent that the customer had made a shortfall payment with respect to one or more preceding months or years (as applicable). As of March 31, 2012, we recorded an aggregate of $3.2 million of deferred revenue, of which $1.8 million is included in accounts receivable as of March 31, 2012, with respect to shortfall payments that could reduce gathering fees received in the next one month to nine years to the extent that a customer's throughput volumes exceed its MVC.
•: To the extent that a customer's throughput volumes exceed its MVC in the applicable period, it is entitled to apply the excess throughput against its aggregate MVC, thereby reducing the period for which its annual MVC applies. For example, one of our DFW Midstream customers has a contracted MVC term from October 2010 through September 2017. However, this customer has regularly shipped excess natural gas on our DFW Midstream system relative to its MVC. Assuming its throughput rate remains at this level, we estimate that it will satisfy the requirements of its aggregate MVC by the end of 2012, thereby reducing the period for which its MVC applies from eight years to less than three years. As a result of this mechanism, the weighted average remaining period for which our MVCs apply is less than the weighted average of the original stated terms of our MVCs.
•: To the extent that a customer's throughput volumes exceed its MVC for the applicable period, there is a crediting mechanism that allows the customer to build a "bank" of credits that it can utilize in the future to reduce shortfall payments owed in future periods, subject to expiration in the event that there is no shortfall in subsequent periods. In such a situation, we would receive lower gathering fees in a particular contract year than we would otherwise be entitled to receive under the customer's MVC.

Under certain circumstances, some or all of these provisions can apply in combination with one another. It is possible that the combined effect of these mechanisms could result in our receiving no revenues or cash flows from one or more customers in periods where those customers are shipping volumes on our systems. In this circumstance, we would incur compression and other operating expenses with no corresponding revenues, which would exacerbate the effect of these provisions on our results of operations. In the most extreme circumstances we could:

•: incur operating expenses with no corresponding revenues from one or more significant customers for a period of up to 35 months; or
•: all or a substantial portion of our customers could cease shipping throughput volumes at a time when their respective aggregate MVCs have been satisfied with previous throughput volume shipments.

If either of these circumstances were to occur, it would have a material adverse effect on our results of operations, financial condition and cash flows and our ability to make distributions to our unitholders.

We do not intend to obtain independent evaluations of natural gas reserves connected to our gathering and transportation systems on a regular or ongoing basis; therefore, in the future, volumes of natural gas on our systems could be less than we anticipate.

We do not have and we do not intend to obtain independent evaluations of natural gas reserves connected to our systems on a regular or ongoing basis. Moreover, even if we did obtain independent evaluations of natural gas reserves connected to our systems, such evaluations may prove to be incorrect. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, future production levels and operating and development costs.

Accordingly, we may not have accurate estimates of total reserves dedicated to some or all of our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering and transportation systems are less than we anticipate and we are unable to secure additional sources of natural gas, it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.

We compete with other midstream companies in our areas of operation. Some of our competitors are large companies that have greater financial, managerial and other resources than we do. In addition, some of our competitors have assets in closer proximity to gas supplies and have available idle capacity in existing assets that would not require new capital investments for use. Our competitors may expand or construct gathering systems that would create additional competition for the services we provide to our customers. Because our customers do not have leases that cover the entirety of our AMIs, non-customer producers that lease acreage within one of our AMIs 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 in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flow could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

We may not be able to renew or replace expiring contracts at favorable rates or on a long-term basis.

We gather the natural gas on our systems under contracts with terms of various durations. As these contracts expire, we may have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. We may be unable to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. Moreover, we may be unable to obtain AMIs from new customers in the future, and we may be unable to renew existing AMIs with current customers as and when they expire. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:

•: the level of existing and new competition to provide gathering services to our markets;
•: the macroeconomic factors affecting natural gas gathering economics for our current and potential customers;
•: the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;

•: the extent to which the customers in our markets are willing to contract on a long-term basis; and
•: the effects of federal, state or local regulations on the contracting practices of our customers.

To the extent we are unable to renew our existing contracts on terms that are favorable to us or successfully manage our overall contract mix over time, our revenues and cash flows could decline and our ability to make distributions to our unitholders could be materially and adversely affected.

We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties, and any material nonpayment or nonperformance by one or more of these parties could adversely affect our financial and operating results.

Although we attempt to assess the creditworthiness of our customers, suppliers and contract counterparties, there can be no assurance that our assessments will be accurate or that there will not be a rapid or unanticipated deterioration in their creditworthiness, which may have an adverse impact on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. In addition, there can be no assurance that our counterparties will perform or adhere to existing or future contractual arrangements.

The procedures and policies 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 procedures and policies prove to be inadequate, our financial and operational results may be negatively impacted.

Some of our counterparties may be highly leveraged or have limited financial resources and will be subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with such parties. In addition, volatility in commodity prices might have an impact on many of our counterparties, which, in turn, could have a negative impact on their ability to meet their obligations to us and may also increase the magnitude of these obligations.

Any material nonpayment or nonperformance by our counterparties could require us to pursue substitute counterparties for the affected operations, reduce operations or provide alternative services. There can be no assurance that any such efforts would be successful or would provide similar financial and operational results.

If third-party pipelines or other midstream facilities interconnected to our gathering systems become partially or fully unavailable, or if the volumes we gather do not meet the natural gas quality requirements of such pipelines or facilities, our revenue and cash flow and our ability to make distributions to our unitholders could be adversely affected.

Our natural gas gathering pipelines connect to other pipelines and midstream facilities, such as processing plants, owned and operated by unaffiliated third parties, such as Energy Transfer Partners, L.P., Enterprise Products Partners L.P. and others. For example, all of the volumes we currently gather on the Grand River system are delivered to Enterprise Products Partners L.P.'s processing plant in Meeker, Colorado. The continuing operation of such third-party pipelines and other midstream facilities is not within our control. These pipelines and other midstream facilities may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from other operational hazards. In addition, if the costs to us to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurred, if any of these pipelines or other midstream facilities become unable to receive or transport natural gas, or if the volumes we gather do not meet the natural gas quality

requirements of such pipelines or facilities, our revenue, cash flow and ability to make cash distributions to our unitholders could be adversely affected.

We have a limited ownership history with respect to all of our assets. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with our pipelines that could have a material adverse effect on our business and operating results.

We purchased the substantial majority of our initial assets from Energy Future Holdings and Chesapeake in September 2009 and from Encana in October 2011. The initial members of our executive management team were hired shortly before our initial purchase from Energy Future Holdings and, consequently, have a limited history of operating our assets. There may be historical occurrences or latent issues regarding our pipeline systems that our executive management team may be unaware of and that may have a material adverse effect on our business and results of operations. The steeper production decline curves associated with unconventional resource plays may require us to incur higher maintenance capital expenditures over time to connect additional wells and maintain throughput volume. Any significant increase in maintenance and repair expenditures or loss of revenue due to the condition of our pipeline systems could adversely affect our business and results of 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, which could have a material adverse effect on our business and results of operations.

The gathering of natural gas requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. We have from time to time encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially and adversely affected. If our labor prices increase or if we experience materially increased health and benefit costs with respect to our general partner's employees, our results of operations could be materially and adversely affected.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not adequately insured or if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, our operations and financial results could be adversely affected.

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

•: damage to pipelines and plants, related equipment and surrounding properties caused by tornadoes, floods, fires and other natural disasters and acts of terrorism;
•: inadvertent damage from construction, vehicles, farm and utility equipment;
•: leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities;
•: ruptures, fires and explosions; and
•: other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. The location of certain of our systems in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from these risks.

These risks may also result in curtailment or suspension of our operations. A natural disaster or any event such as those described above affecting the areas in which we and our customers operate could have a material adverse effect on our operations. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segments of our systems. Potential customer impacts arising from service interruptions on segments of our systems could include limitations on our ability to satisfy customer requirements, obligations to temporarily waive minimum volume commitments to customers during times of constrained capacity, and solicitation of existing customers by others for potential new projects that would compete directly with existing services. Such circumstances could adversely impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business and results of operations and our ability to make cash distributions to our unitholders.

Although we have a range of insurance programs providing varying levels of protection for public liability, damage to property, loss of income and certain environmental hazards, we may not be insured against all causes of loss, claims or damage that may occur. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, with regard to the assets we have acquired, we have limited indemnification rights to recover for potential environmental liabilities.

None of the proceeds of this offering will be used to maintain or grow our asset base.

None of the proceeds of this offering will be used to maintain or grow our asset base, which may be necessary to pay future distributions at the then-current level. The net proceeds of the offering will be used to repay amounts outstanding under our amended and restated revolving credit facility and to make a cash distribution to Summit Investments to reimburse Summit Investments for certain capital expenditures it incurred with respect to assets it contributed to us.

We intend to grow our business in part by seeking strategic acquisition opportunities. If we are unable to make acquisitions on economically acceptable terms from third parties, our future growth will be affected, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per unit basis.

Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our ability to grow our operations and increase our cash distributions to our unitholders.

If we are unable to make accretive acquisitions from third parties, whether because we are (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, (ii) unable to obtain financing for these acquisitions on economically acceptable terms, (iii) outbid by competitors, or (iv) we are unable to obtain necessary governmental or third-party consents or for any other reason, then our future growth and ability to increase cash distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.

Any acquisition involves potential risks, including, among other things:

•: mistaken assumptions about volumes, revenue and costs, including synergies and potential growth;
•: an inability to secure adequate customer commitments to use the acquired systems or facilities;
•: the risk that natural gas or crude oil reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;
•: an inability to integrate successfully the assets or businesses we acquire;
•: coordinating geographically disparate organizations, systems and facilities;
•: the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;
•: mistaken assumptions about the overall costs of equity or debt;
•: the diversion of management's and employees' attention from other business concerns;
•: unforeseen difficulties operating in new geographic areas and business lines; 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 not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

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 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 our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control. Such expansion projects may also require the expenditure of significant amounts of capital, and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, our revenue may not increase immediately upon the expenditure of funds on a particular project.

For instance, as we develop our medium pressure system to serve the Niobrara Shale formation, the construction will occur over an extended period of time, yet we will not receive any material increases in revenue until the project is completed and placed into service. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize or only materializes over a period materially longer than expected. Since we are not engaged in the exploration for and development of natural gas and oil reserves, we often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in

that area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate as a result of the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not attract enough throughput to achieve our expected investment return, which could 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 state environmental or other authorizations. The approval process for gathering activities has become increasingly challenging, due in part to state and local concerns related to unregulated exploration and production and gathering activities in new production areas. Such authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions. As a result, we may be unable to obtain such rights-of-way or other authorizations and may, therefore, be unable to connect new natural gas volumes to our systems or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or authorizations or to renew existing rights-of-way or authorizations. If the cost of renewing or obtaining new rights-of-way or authorizations increases materially, our cash flows could be adversely affected.

We require access to significant amounts of additional capital to implement our growth strategy, as well as to meet potential future capital requirements under certain of our gas gathering agreements. Tightened capital markets could impair our ability to grow or cause us to be unable to meet future capital requirements.

In order to expand our asset base, whether through acquisitions or organic growth, we will need to make expansion capital expenditures. We expect to make substantial expansion capital expenditures during the twelve months ending June 30, 2013. We also frequently consider and enter into discussions with third parties regarding potential acquisitions. In addition, the terms of certain of our gas gathering agreements may also require us to spend significant amounts of capital, including over a short period of time, to construct and develop additional midstream assets to support our customers' development projects. Depending on our customers' future development plans, it is possible that the capital we would be required to spend to construct and develop such assets could exceed our ability to finance those expenditures using our cash reserves or available capacity under our amended and restated credit facility.

We will be required to use cash from operations or incur borrowings or sell additional common units or other securities in order to fund our future expansion capital expenditures. Using cash from operations to fund expansion capital expenditures will directly reduce our cash available for distribution to unitholders. Our ability to obtain financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering as well as covenants in our debt agreements, general economic conditions and contingencies and uncertainties that are beyond our control. If we are unable to raise expansion capital, we may lose the opportunity to make acquisitions or to gather natural gas production from new upstream projects developed by our customers with whom we have agreed to construct and develop midstream assets in the future. Even if we are successful in obtaining funds for expansion capital expenditures through equity or debt financings, the terms thereof could limit our ability to pay distributions to our common unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional units representing limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.

We do not have any commitment from our sponsors or their affiliates, including Energy Capital Partners and GE Energy Financial Services, to provide any direct or indirect financial assistance to us following the closing of this offering.

Because our common units will be yield-oriented securities, increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

Interest rates are generally at or near historic lows and may increase in the future. As a result, interest rates on our future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

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

Upon the closing of this offering, we expect to have approximately $ million of total indebtedness and $ million available for future borrowings under our amended and restated revolving credit facility. Our future level of debt could have important consequences to us, including the following:

•: our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
•: our funds available for operations, future business opportunities and cash distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;
•: we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
•: our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.

Restrictions in our amended and restated revolving credit facility could adversely affect our business, financial condition, results of operations, ability to make 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 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; 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 to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests. Please see "Management's Discussion and Analysis of Financial Condition and Results of Operation—Liquidity and Capital Resources—Our Amended and Restated Revolving Credit Facility" for additional information.

The provisions of our amended and restated revolving credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our amended and restated revolving credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.

A portion of our revenues are exposed to changes in oil and natural gas prices, and our exposure may increase in the future.

For the year ended December 31, 2011 and the three months ended March 31, 2012, we generated approximately 80% and 86%, respectively, of our revenues pursuant to long-term, fee-based gas gathering agreements under which we are paid based on the volumes of natural gas that we gather rather than the value of the underlying natural gas. Consequently, our existing operations and cash flows have limited exposure to direct commodity price risk. Although we intend to enter into similar fee-based contracts with new customers in the future, our efforts to obtain such contractual terms may not be successful. For example, in the future we may enter into percent-of-proceeds contracts with our customers, which would increase our exposure to commodity price risk, as the revenues generated from those contracts directly correlate with the fluctuating price of natural gas and NGLs.

Substantially all of our remaining revenue is derived from (i) the sale of physical natural gas that we retain from our DFW Midstream customers to offset our power expense associated with our electric-drive compression and (ii) the sale of condensate volumes that we collect on the Grand River system. Our revenues with respect to our 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 fom the sale of condensate.

Furthermore, we may acquire or develop additional midstream assets in the future, including assets related to commodities other than natural gas, that have a greater exposure to fluctuations in commodity price risk than our current operations. Future exposure to the volatility of 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 may cause our operating and maintenance expenses to increase or revenue to decline.

Various aspects of our operations are subject to extensive and frequently changing regulation as the activities of the natural gas industry often are reviewed by legislators and regulators. More stringent legislation or regulation or taxation of natural gas drilling activity could directly curtail such activity or increase the cost of drilling, resulting in reduced levels of drilling activity and therefore reduced demand for our services. Numerous federal, state and local departments and agencies are authorized by statute to issue, and have issued, rules and regulations binding upon participants in the natural gas industry. Our operations and the markets in which we participate are affected by these laws and regulations and may be affected by changes to such laws and regulations, which may cause us to incur materially increased operating costs or realize materially lower revenues or both.

Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenues.

A portion of our customers' natural gas production is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. We do not engage in any hydraulic fracturing activities although many of our customers do. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of "underground injection" and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the Safe Drinking Water Act. Any such legislation could make it easier for third parties opposed to hydraulic fracturing to initiate legal proceedings against our customers. In addition, the federal government is currently undertaking several studies of hydraulic fracturing's potential impacts, the results of which are expected to be available between late 2012 and 2014. On May 4, 2012, the Department of the Interior's Bureau of Land Management ("BLM") 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 BLM after fracturing operations have been completed and includes provisions addressing well-bore integrity and flowback water management plans. Several states, including states in which our customers do business, such as Texas and Colorado, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. The chemical ingredient information for hydraulic fracturing fluid is generally available to the public through online databases, and this may bring more public scrutiny to hydraulic fracturing operations. We cannot predict whether any other legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs and prohibitions for producers who drill near our pipelines which could reduce the volumes of natural gas available to move through our gathering systems, which could materially adversely affect our revenue and results of operations.

We are subject to federal anti-market manipulation laws and regulations, potentially other federal regulatory requirements, and state and local regulation, and could be materially affected by changes in such laws and regulations, or in the way they are interpreted and enforced.

We believe that our pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of the Federal Energy Regulatory Commission, also known as FERC, under the Natural Gas Act of 1938, also known as the NGA, and the Natural Gas Policy Act of 1978, also known as the NGPA. We are, however, subject to the anti-market manipulation provisions in the NGA, as amended by the Energy Policy Act of 2005, also known as EPAct 2005, and to FERC's regulations thereunder,

which authorize FERC to impose fines of up to one million dollars ($1,000,000) per day per violation of the NGA or its implementing regulations. In addition, the Federal Trade Commission, also known as FTC, holds statutory authority under the Energy Independence and Security Act of 2007, also known as the EISA, to prevent market manipulation in oil markets, and has adopted broad rules and regulations prohibiting fraud and market manipulation. FTC is also authorized to seek fines of up to one million dollars ($1,000,000) per day per violation. The Commodity Futures Trading Commission, also known as the CFTC, is directed under the Commodity Exchange Act, also known as the CEA, to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act, also known as the Dodd-Frank Act, and other authority, CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. CFTC also has statutory authority to seek civil penalties of up to the greater of one million dollars ($1,000,000) or triple the monetary gain to the violator for each violation of the anti-market manipulation sections of the CEA.

The distinction between federally-unregulated gathering facilities and FERC-regulated transmission pipelines has been the subject of extensive litigation and may be determined by FERC on a case-by-case basis, although FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of some of our pipelines could change based on future determinations by FERC or the courts. If our gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers.

State and municipal regulations also affect our business. We are subject to state and local regulation regarding the construction and operation of our gathering systems, as well as state ratable take statutes and regulations. Regulation of the construction and operation of our facilities may affect our ability to expand our facilities or build new facilities and such regulation may cause us to incur additional operating costs or limit the quantities of gas we may gather. Ratable take statutes and regulations generally require gatherers to take natural gas production that may be tendered for gathering without undue discrimination. These requirements restrict our right to decide whose production we gather. Many states have adopted complaint-based regulation of gathering activities, which allows producers and shippers to file complaints with state regulators in an effort to resolve access issues, rate grievances, and other matters. Other state and municipal regulations do not directly apply to our business, but may nonetheless affect the availability of natural gas for gathering, including state regulation of production rates, maximum daily production allowable from gas wells, and other activities related to drilling and operating wells. While our facilities currently are subject to limited state and local regulation, there is a risk that state or local laws will be changed or reinterpreted, which may materially affect our operations, operating costs, and revenues.

We are subject to stringent laws and regulations that may expose us to significant costs and liabilities.

Our natural gas gathering, compression and dehydrating operations are subject to stringent and complex federal, state and local environmental laws and regulations, including laws and regulations regarding the discharge of materials into the environment or otherwise relating to environmental protection. Examples of these laws include:

•: the federal Clean Air Act and analogous state laws that impose obligations related to air emissions;
•: the federal Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or the Superfund law, and analogous state laws that regulate the cleanup of hazardous substances that may be or have been released at properties currently or previously

owned or operated by us or at locations to which our wastes are or have been transported for disposal;

•: the federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws that regulate discharges from our facilities into state and federal waters, including wetlands;
•: the federal Oil Pollution Act, also known as OPA, 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, also known as RCRA, and analogous state laws that impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities;
•: the Endangered Species Act, also known as the ESA; and
•: the Toxic Substances Control Act, also known as TSCA, and analogous state laws that impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.

These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations or at locations currently or previously owned or operated by us. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions or costly pollution control measures. Failure to comply with these laws, regulations and permits may result in the assessment of significant administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue.

There is a risk that we may incur significant environmental costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of hydrocarbons and other wastes and potential emissions and discharges related to our operations. Joint and several, strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbon wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the properties through which our gathering systems pass and facilities where our wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. In addition, changes in environmental laws occur frequently, and any such changes that result in additional permitting obligations or more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. We may not be able to recover all or any of these costs from insurance. Please read "Business—Environmental Matters" for more information.

We may incur greater than anticipated costs and liabilities as a result of pipeline safety requirements.

The U.S. Department of Transportation, also known as DOT, through its Pipeline and Hazardous Materials Safety Administration, also known as PHMSA, has adopted and enforces safety standards and procedures applicable to our pipelines. In addition, many states, including the states in which we operate, have adopted regulations similar to existing DOT regulations for intrastate pipelines. Among the regulations applicable to us, PHMSA requires pipeline operators to develop integrity management programs for certain pipelines located in "high consequence areas," which include high population areas such as the Dallas-Fort Worth greater metropolitan area where our DFW Midstream system is located. While the majority of our pipelines meet the DOT definition of gathering lines and are thus exempt from PHMSA's integrity management requirements, we also operate three pipelines in the Dallas-Fort Worth area that are subject to the integrity management requirements. The regulations require operators, including us, to:

•: perform ongoing assessments of pipeline integrity;
•: identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
•: maintain processes for data collection, integration and analysis;
•: repair and remediate pipelines as necessary; and
•: implement preventive and mitigating actions.

Our pipelines have become subject to increased penalties and may become subject to more stringent safety regulation.

Recently enacted pipeline safety legislation, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, reauthorizes funding for federal pipeline safety programs through 2015, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. PHMSA has also 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 gathering lines. While we believe that we are in compliance with existing safety laws and regulations, increased penalties for safety violations and potential regulatory changes could have a material effect on our operations, operating and maintenance expenses, and revenues. Extending the integrity management requirements to our gathering lines would impose additional obligations on us and could add material costs to our operations.

Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the natural gas services we provide.

In recent years, the U.S. Congress has considered legislation to restrict or regulate emissions of greenhouse gases, or GHGs, such as carbon dioxide and methane, that may be contributing to global warming. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address GHG emissions, primarily through the planned development of emission inventories or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. In general, the number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. Depending

on the scope of a particular program, we could be required to purchase and surrender allowances for GHG emissions resulting from our operations (e.g., at compressor stations). Although most of the state-level initiatives have to date been focused on large sources of GHG emissions, such as electric power plants, it is possible that our sources, such as our gas-fired compressors, could become subject to state-level GHG-related regulation. Depending on the particular program, we may be required to control emissions or to purchase and surrender allowances for GHG emissions resulting from our operations.

Independent of Congress, the EPA has begun to adopt federal-level regulations controlling GHG emissions under its existing Clean Air Act authority. In 2009, the EPA issued required findings under the Clean Air Act concluding that emissions of GHGs present an endangerment to human health and the environment , and issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule for petroleum and natural gas facilities. These rules require data collection beginning in 2011 and reporting beginning in September 2012. We are required to report our GHG emissions for certain of our assets. On May 12, 2010, the EPA also issued a final rule, known as the "Tailoring Rule," that makes certain large stationary sources and modification projects subject to permitting requirements for GHG emissions under the Clean Air Act. As a result of this continued regulatory focus, future GHG regulations 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 GHG emissions would impact our business, either directly or indirectly, any future federal or state laws or implementing regulations that may be adopted to address GHG emissions could require us to incur increased operating costs and could adversely affect demand for the natural gas we gather or otherwise handle in connection with our services. The potential increase in the costs of our operations resulting from any legislation or regulation to restrict emissions of GHGs could include new or increased costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions and administer and manage a GHG emissions program. While we may be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities, such recovery of costs is uncertain. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for natural gas, resulting in a decrease in demand for our services. We cannot predict with any certainty at this time how these possibilities may affect our operations.

The adoption and implementation of new statutory and regulatory requirements for swap transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

In July 2010 Congress enacted the Dodd-Frank Act. The Dodd-Frank Act provides new statutory requirements for swap transactions, including oil and gas hedging transactions. These statutory requirements must be implemented through regulation, primarily through rules to be adopted by the CFTC. The Dodd-Frank Act provisions are intended to change fundamentally the way swap transactions are entered into, transforming an over-the-counter market in which parties negotiate directly with each other into a regulated market in which most swaps are to be executed on registered exchanges or swap execution facilities and cleared through central counterparties. Many market participants will be newly regulated as swap dealers or major swap participants, with new regulatory capital requirements and other regulations that may impose business conduct rules and mandate how they hold collateral or margin for swap transactions. All market participants will be subject to new reporting and recordkeeping requirements.

We currently receive a fuel retainage fee from certain of our customers that is paid in-kind to offset the costs we incur to operate our electric-drive compression assets in the Barnett Shale. We

currently enter into forward contracts with third parties to buy power and sell natural gas in an attempt to hedge our exposure to fluctuations in the price of natural gas with respect to those volumes. The impact of the Dodd-Frank Act on our hedging activities is uncertain at this time, and the CFTC has not yet promulgated final regulations implementing the key provisions. Although we do not believe we will need to register as a swap dealer or major swap participant, and do not believe we will be subject to the new requirements to trade on an exchange or swap execution facility or to clear swaps through a central counterparty, we may have new regulatory burdens. Moreover, the changes to the swap market as a result of Dodd-Frank implementation could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reduce the availability of new or existing swaps.

Depending on the rules and definitions adopted by the CFTC, we might in the future be required to provide cash collateral for our commodities hedging transactions under circumstances in which we do not currently post cash collateral. Posting of such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures or other partnership purposes. A requirement to post cash collateral could therefore reduce our willingness or ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of swaps as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.

We do not own all of the land on which our pipelines and facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate or if our pipelines are not properly located within the boundaries of such rights-of-way. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. If we were to be unsuccessful in renegotiated rights-of-way, we might have to relocate our facilities. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Our ability to operate our business effectively could be impaired if we fail to attract and retain key management personnel.

Our ability to operate our business and implement our strategies will depend on our continued ability to attract and retain highly skilled management personnel with midstream natural gas industry experience and competition for these persons in the midstream natural gas industry is intense. Given our size, we may be at a disadvantage, relative to our larger competitors, in the competition for these personnel. We may not be able to continue to employ our senior executives and key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract our senior executives and key personnel could have a material adverse effect on our ability to effectively operate our business.

If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results timely and accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.

Prior to this offering, we have not been required to file reports with the SEC. Upon the completion of this offering, we will become subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act, including the rules thereunder that will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Effective internal controls are necessary for us to provide reliable and timely financial reports, prevent fraud and to operate successfully as a publicly traded partnership. We prepare our consolidated financial statements in accordance with GAAP, but our internal accounting controls may not meet all standards applicable to companies with publicly traded securities. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, or Sarbanes-Oxley, which we refer to as Section 404.

Given the difficulties inherent in the design and operation of internal controls over financial reporting, in addition to our limited accounting personnel and management resources, we can provide no assurance as to our, or our independent registered public accounting firm's, future conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Any failure to implement and maintain effective internal controls over financial reporting will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

Although we will be required to disclose changes made in our internal control and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the fiscal year ending December 31, 2013. In addition, pursuant to the recently enacted JOBS Act, our independent registered public accounting firm will not be required to formally attest to the effectiveness of our internal control over financial reporting until the later of the year following our first annual report required to be filed with the SEC or the date we are no longer an "emerging growth company," which may be up to five full fiscal years following this offering.

The amount of cash we have available for distribution to holders of our common and subordinated units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

Risks Inherent in an Investment in Us

Summit Investments owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations and limited duties to us and our unitholders. Summit Investments and our general partner have conflicts of interest with us and they may favor their own interests to the detriment of us and our other common unitholders.

Following this offering, Summit Investments will control our general partner, and appoint all of the officers and directors of our general partner, some of whom will also be officers, directors or principals

of Energy Capital Partners and GE Energy Financial Services, the entities that own and control Summit Investments. Although our general partner has a duty to manage us in a manner that is in our best interests, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is in the best interests of its owner, Summit Investments. Conflicts of interest will arise between Summit Investments, its owners and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of Summit Investments and its owners over our interests and the interests of our unitholders. These conflicts include the following situations, among others:

•: Neither our partnership agreement nor any other agreement requires Summit Investments or its owners to pursue a business strategy that favors us, and the directors and officers of Summit Investments have a fiduciary duty to make these decisions in the best interests of the owners of Summit Investments, which may be contrary to our interests. Summit Investments may choose to shift 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 to third parties without first offering us the right to bid for them.
•: Our general partner is allowed to take into account the interests of parties other than us, such as Summit Investments and its owners, in resolving conflicts of interest.
•: Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner to us and our unitholders with contractual standards governing its duties to us and our unitholders. These contractual standards limit our general partner's liabilities and the rights of our unitholders with respect to actions that, without the limitations, might constitute breaches of fiduciary duty.
•: Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
•: Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.
•: Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert to common units.
•: Our general partner determines which costs incurred by it are reimbursable by us.
•: Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.
•: Our partnership agreement permits us to classify up to $ million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights.

•: Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.
•: Our general partner intends to limit its liability regarding our contractual and other obligations.
•: Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.
•: Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.
•: Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
•: Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner's incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Please read "Conflicts of Interest and Duties."

Our sponsors are not limited in their ability to compete with us and are not obligated to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could adversely affect our results of operations and cash available for distribution to our unitholders.

Energy Capital Partners and GE Energy Financial Services have significantly greater resources than us and have experience making investments in midstream energy businesses. Energy Capital Partners and GE Energy Financial Services may compete with us for investment opportunities and may own interests in entities that compete with us. Energy Capital Partners and GE Energy Financial Services are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. For example, GE Energy Financial Services owns an interest in another publicly traded midstream master limited partnership. In addition, in the future, Energy Capital Partners or GE Energy Financial Services may acquire, construct or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities. Moreover, while Energy Capital Partners or GE Energy Financial Services may offer us the opportunity to buy additional assets, neither of them are under any contractual obligation to do so and we are unable to predict whether or when such opportunities may arise.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner, its officers and directors or any of its affiliates, including our sponsors and their respective executive officers, directors and principals. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders. Please read "Conflicts of Interest and Duties."

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the market price of our common units may fluctuate significantly, and you could lose all or part of your investment.

Prior to this offering, there has been no public market for our common units. After this offering, there will be only publicly traded common units, assuming no exercise of the underwriters' option to purchase additional common units. In addition, affiliates of our general partner will own common and subordinated units, representing an aggregate % limited partner interest in us. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also 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 after this offering or changes in financial estimates by analysts;
•: future sales of our common units; and
•: other factors described in these "Risk Factors."

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

Our partnership agreement contains provisions that eliminate fiduciary duties to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner or otherwise, free of any duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

•: how to allocate corporate opportunities among us and its affiliates;
•: whether to exercise its limited call right;
•: whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;
•: how to exercise its voting rights with respect to the units it owns;

•: whether to exercise its registration rights;
•: whether to elect to reset target distribution levels;
•: whether to transfer the incentive distribution rights or any units it owns to a third party; and
•: whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read "Conflicts of Interest and Duties—Duties of our General Partner."

Our partnership agreement limits the liabilities of our general partner and the rights of our unitholders with respect to actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that limit the liability of our general partner and the rights of our unitholders with respect to actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

•

whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in our best interests, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

•

our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;

•

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

•

our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:

•: approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;
•: approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;
•: determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
•: determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the final two subclauses above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read "Conflicts of Interest and Duties."

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

Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner's fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

In addition, because we distribute all of our available cash, we may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our amended and restated revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by affiliates of our general partner) after the subordination period has ended. At the closing of this offering, affiliates of our general partner will

own, directly or indirectly, approximately % of the outstanding common units and all of our outstanding subordinated units. Please read "The Partnership Agreement—Amendment of Our Partnership Agreement."

Reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our common unitholders. The amount and timing of such reimbursements will be determined by our general partner.

Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including Summit Investments, for expenses they incur and payments they make on our behalf. Under our partnership agreement, we will reimburse our general partner and its affiliates for certain expenses incurred on our behalf, including administrative costs, such as compensation expense for those persons who provide services necessary to run our business, which we project to be approximately $19.5 million for the twelve months ending June 30, 2013. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our common unitholders. Please read "Our Cash Distribution Policy and Restrictions on Distributions."

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the minimum quarterly distribution and the target distribution levels related to our general partner's incentive distribution rights without the approval of the conflicts committee of our general partner's board or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters (and the amount of each such distribution did not exceed adjusted operating surplus for such quarter), to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the "reset minimum quarterly distribution"), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

In the event of a reset of target distribution levels, our general partner will be entitled to receive the number of common units equal to that number of common units that would have entitled it to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions on the incentive distribution rights in the prior two quarters. Our general partner will also be issued the number of general partner units necessary to maintain its general partner interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then-current

business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels related to our general partner's incentive distribution rights. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner's Right to Reset Incentive Distribution Levels."

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

Unlike the holders of common stock in a corporation, 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 or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner will be chosen by Summit Investments. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

The unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon the closing of this offering to be able to prevent its removal. The vote of the holders of at least 66²/3% of all outstanding limited partner units voting together as a single class is required to remove our general partner. Following the closing of this offering, affiliates of our general partner will own % of our outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholder's dissatisfaction with our general partner's performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

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

Unitholders' voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Summit Investments to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers. This effectively permits a "change of control" without the vote or consent of the unitholders.

The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer the incentive distribution rights it owns to a third party at any time without the consent of our unitholders. If our general partner transfers the incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our business and increase quarterly distributions to unitholders over time as it would if it had retained ownership of the incentive distribution rights. For example, a transfer of the incentive distribution rights by our general partner could reduce the likelihood of Summit Investments selling or contributing additional midstream assets to us, as Summit Investments would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

You will experience immediate and substantial dilution in net tangible book value of $ per common unit.

The estimated initial public offering price of $ per common unit exceeds our net tangible book value of $ per unit. Based on the estimated initial public offering price of $ per common unit, you will incur immediate and substantial dilution of $ per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded in accordance with GAAP at their historical cost, and not their fair value. Please read "Dilution."

We may issue additional units without your approval, which would dilute your existing ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to the common units, that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

•: our existing unitholders' proportionate ownership interest in us will decrease;
•: the amount of cash available for distribution on each unit may decrease;
•: because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
•: because the amount payable to holders of incentive distribution rights is based on a percentage of the total cash available for distribution, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;
•: the ratio of taxable income to distributions may increase;

•: the relative voting strength of each previously outstanding unit may be diminished; and
•: the market price of the common units may decline.

Summit Investments may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

After the sale of the common units offered by this prospectus, assuming that the underwriters do not exercise their option to purchase additional common units, Summit Investments will hold an aggregate of common units and subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. In addition, we have agreed to provide Summit Investments with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of our outstanding common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the closing of this offering, and assuming no exercise of the underwriters' option to purchase additional common units, Summit Investments will own approximately % of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than upon the conversion of the subordinated units), Summit Investments will own approximately % of our outstanding common units. For additional information about this right, please read "The Partnership Agreement—Limited Call Right."

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

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were 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
•: your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute "control" of our business.

For a discussion of the implications of the limitations of liability on a unitholder, please read "The Partnership Agreement—Limited Liability."

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

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

We intend to apply to list our common units on the NYSE. Because we will be a publicly traded partnership, the NYSE does not require us to have, and we do not intend to have, a majority of independent directors on our general partner's board of directors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE's shareholder approval rules. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read "Management."

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

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 and related rules subsequently implemented by the SEC and the NYSE have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded partnership reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and to possibly result in our general partner having to accept reduced policy limits and coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers.

We have included $2.5 million of estimated annual incremental costs associated with being a publicly traded partnership in our financial forecast included elsewhere in this prospectus. However, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

Tax Risks

In addition to reading the following risk factors, please read "Material Federal Income Tax Consequences" for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service (IRS) were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are or will be so treated, a change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, there would be material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to you. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

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

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation

at any time. For example, from time to time members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships. Currently, one such legislative proposal would eliminate the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. Please read "—Partnership Status." We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.

Our unitholders' share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

Because a unitholder will be treated as a partner to whom we will allocate taxable income which could be different in amount than the cash we distribute, a unitholder's allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if the unitholder receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take, and the IRS's positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel's conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

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

If you sell your common units, you will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common units you sell 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 your common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss."

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

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example,

virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.

We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. Our counsel is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read "Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election."

We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We will prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations and, although the U.S. Treasury Department issued proposed regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. Accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees."

A unitholder whose common units are loaned to a "short seller" to effect a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose common units are loaned to a "short seller" to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units; therefore, our

unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

We will adopt certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

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

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and would result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Constructive Termination."

As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if the unitholders do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We initially expect to conduct business in Texas and Colorado. Colorado currently imposes a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

USE OF PROCEEDS

We expect to receive net proceeds of approximately $ million, after deducting underwriting discounts, commissions and a structuring fee, but before paying offering expenses, from the issuance and sale of common units offered by this prospectus. Our estimates assume an initial public offering price of $ per common unit. We will use the net proceeds from this offering to:

•: repay $ million outstanding under our revolving credit facility;
•: make a cash distribution to Summit Investments of $ million in order to reimburse Summit Investments for certain capital expenditures it incurred with respect to assets it contributed to us; and
•: pay estimated offering expenses of $ million.

We intend to retain the remainder of the net proceeds for general partnership purposes.

As of July 16, 2012, we had $352.0 million of indebtedness outstanding under our revolving credit facility, with a weighted average interest rate of 2.75%. The revolving credit facility matures on May 26, 2016, and borrowings bear interest at a variable rate per annum equal to either LIBOR, plus the applicable margins ranging from 2.5% to 3.5%, or at a base rate, plus the applicable margins ranging from 1.5% to 2.5%. Borrowings made under our revolving credit facility within the last twelve months were used primarily to make distributions to our sponsors and fund capital expenditures.

If the underwriters exercise their option to purchase additional common units, we will use the net proceeds from that exercise to redeem from Summit Investments the number of common units issued upon such exercise.

The underwriters may, from time to time, engage in transactions with and perform services for us and our affiliates in the ordinary course of business. Affiliates of certain of the underwriters are lenders under our revolving credit facility and will, in that respect, receive a portion of the proceeds from this offering through the repayment of borrowings outstanding under our revolving credit facility. Please read "Underwriting."

An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts, commissions and a structuring fee, to increase or decrease, respectively, by $ million. In addition, we may also increase or decrease the number of common units we are offering. Each increase of 1,000,000 common units offered by us, together with a concurrent $1.00 increase in the assumed public offering price of $ per common unit, would increase net proceeds to us from this offering by approximately $ million. Similarly, each decrease of 1,000,000 common units offered by us, together with a concurrent $1.00 decrease in the assumed initial offering price of $ per common unit, would decrease the net proceeds to us from this offering by approximately $ million. To the extent there is an increase or decrease in the net proceeds we receive from this offering, we will make a corresponding increase or decrease in the cash distribution to Summit Investments.

CAPITALIZATION

The following table shows:

•

Summit Midstream Predecessor's historical cash and cash equivalents and capitalization, as of March 31, 2012; and

•

our as adjusted cash and cash equivalents and capitalization, as of March 31, 2012, giving effect to:

•: our receipt and use of net proceeds of $ million from the issuance and sale of common units to the public at an assumed initial offering price of $ per unit in the manner described in "Use of Proceeds"; and
•: the other transactions described in "Summary—Formation Transactions and Partnership Structure."

We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, our historical consolidated financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations." This table assumes that the underwriters' option to purchase additional common units is not exercised.

	As of March 31, 2012

	Summit Midstream Predecessor Historical		Summit Midstream Partners, LP As Adjusted
	(in thousands)
Cash and cash equivalents	$	10,911	$

Long-Term Debt:
Revolving credit facility(1)	$	147,000	$
Promissory notes payable to sponsors(2)		206,940		—

Total long-term debt		353,940

Membership Interests and Partners' Capital:
Predecessor membership interest		648,317		—
Held by public
Common units(3)		—
Held by Summit Investments
Common units(3)		—
Subordinated units(3)		—
General partner equity(3)		—

Total membership interests and partners' capital

Total capitalization	$	1,002,257	$

(1): On May 7, 2012, we amended and restated our revolving credit facility. On May 8, 2012, we borrowed $163.0 million under this facility and used $160.0 million of those borrowings to repay amounts outstanding under the promissory notes payable to our sponsors. As of July 16, 2012, the outstanding balance under our amended and restated revolving credit facility was approximately $352.0 million.
(2): On July 2, 2012, the remaining balance outstanding under the promissory notes was paid in full. See footnote 1.
(3): As of March 31, 2012, we had no common units, no subordinated units and no general partner units issued and outstanding. On an as adjusted basis, giving effect to the transactions described in "Summary—Formation Transactions and Partnership Structure" and the issuance of common units in this offering, we would have had common units, subordinated units and general partner units issued and outstanding as of March 31, 2012.

DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of March 31, 2012, after giving effect to the offering of common units and the application of the related net proceeds, and assuming the underwriters' option to purchase additional common units is not exercised, our net tangible book value was $ million, or $ per unit. Net tangible book value excludes $ million of net intangible assets. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:


Assumed initial public offering price per common unit		$
Net tangible book value per unit before the offering(1)	$
Increase in net tangible book value per unit attributable to purchasers in the offering

Less: Pro forma net tangible book value per unit after the offering(2)

Immediate dilution in tangible net book value per common unit to purchasers in the offering(3)		$

(1): Determined by dividing the number of units ( common units, subordinated units and general partner units) held by our general partner and its affiliates, including Summit Investments, into the net tangible book value of our assets.
(2): Determined by dividing the total number of units to be outstanding after this offering ( common units, subordinated units and general partner units) into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of this offering.
(3): If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $ and $ , respectively.

The following table sets forth the number of units that we will issue and the total consideration to be contributed to us by our general partner and its affiliates and by the purchasers of common units in this offering upon the closing of the transactions contemplated by this prospectus:

	Units Acquired				Total Consideration

	Number	Percent			Amount	Percent
	(in thousands)
General partner and affiliates(1)(2)(3)					$			%
Purchasers in the offering				%

Total			100.0	%	$		100.0	%

(1): The units acquired by our general partner and its affiliates, including Summit Investments, consist of common units, subordinated units and general partner units.
(2): Assumes the underwriters' option to purchase additional common units is not exercised.
(3): The assets contributed by Summit Investments and its affiliates were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by Summit Investments and its affiliates, as of March 31, 2012, after giving effect to the formation transactions is as follows:

		(in thousands)

Book value of net assets contributed		$
Less: Distribution to Summit Investments from net proceeds of this offering

Total consideration		$

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the factors and assumptions upon which our cash distribution policy is based, which are included under the heading "—Assumptions and Considerations" below. In addition, please read "Forward-Looking Statements" and "Risk Factors" for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business. For additional information regarding our historical operating results, you should refer to our historical financial statements, and the notes thereto, included elsewhere in this prospectus.

General

Our Cash Distribution Policy. Our policy is to distribute to our unitholders an amount of cash each quarter that is equal to or greater than the minimum quarterly distribution stated in our partnership agreement. To that end, our partnership agreement requires us to distribute all of our available cash quarterly. Generally, our available cash is our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case were we subject to federal income tax.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy. There is no guarantee that our unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or any other distribution except to the extent we have available cash as defined in our partnership agreement. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including the following:

•: Our cash distribution policy will be subject to restrictions on distributions under our revolving credit facility or other debt agreements entered into in the future. Our revolving credit facility contains financial tests and covenants that we must satisfy. Should we be unable to satisfy these restrictions, we may be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Amended and Restated Revolving Credit Facility."
•: Our general partner will have the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment or increase of those cash reserves could result in a reduction in cash distributions to you from the levels we currently anticipate pursuant to our stated distribution policy. Any determination to establish cash reserves made by our general partner in good faith will be binding on our unitholders.
•: Although our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to distribute all of our available cash, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders other than in certain limited circumstances where no unitholder approval is required. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by Summit Investments) after the subordination period has ended. At the closing of this offering, Summit Investments will own our general partner as well as approximately % of our outstanding common units and all of our subordinated units, representing an aggregate % 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 policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.
•: Under Section 17-607 of the Delaware Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.
•: We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our cash available for distribution to unitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Available Cash."
•: If and to the extent our cash available for distribution materially declines, we may elect to reduce our quarterly distribution rate in order to service or repay our debt or fund expansion capital expenditures.

All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. We anticipate that distributions from operating surplus will generally not represent a return of capital. However, operating surplus, as defined in our partnership agreement, includes certain components, including a $ million cash basket, that represent non-operating sources of cash. Consequently, it is possible that distributions from operating surplus may represent a return of capital. Any cash distributed by us in excess of operating surplus will be deemed to be capital surplus under our partnership agreement. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. We do not anticipate that we will make any distributions from capital surplus.

Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital. Our partnership agreement requires us to distribute all of our available cash to our unitholders. As a result, we expect that we will rely primarily upon external financing sources, including borrowings under our amended and restated revolving credit facility and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. To the extent we are unable to finance growth with external sources of capital, our cash distribution policy will significantly impair our ability to grow. In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions, expansion capital expenditures or otherwise, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no restrictions in our partnership agreement or our amended and restated revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional bank borrowings (under our amended and restated revolving credit facility or otherwise) or other debt to finance our growth strategy would result in increased interest expense, which in turn, may impact the available cash that we have to distribute to our unitholders.

Our Minimum Quarterly Distribution

Upon completion of this offering, the board of directors of our general partner will establish a minimum quarterly distribution of $ per unit per complete quarter, or $ per unit per year, to be paid no later than 45 days after the end of each fiscal quarter beginning with the quarter

ending , 2012. This equates to an aggregate cash distribution of approximately $ million per quarter, or approximately $ million per year, based on the number of common and subordinated units and the 2.0% general partner interest to be outstanding immediately after the completion of this offering. Our ability to make cash distributions equal to the minimum quarterly distribution pursuant to this policy will be subject to the factors described above under the caption "—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy."

If and to the extent the underwriters exercise their option to purchase additional common units, we will use the net proceeds from that exercise to redeem from Summit Investments a number of common units equal to the number of common units issued upon such exercise, at a price per common unit equal to the proceeds before expenses but after deducting underwriting discounts, commissions and structuring fees. Accordingly, the exercise of the underwriters' option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read "Underwriting."

Initially, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. In the future, our general partner's initial 2.0% interest in these distributions may be reduced if we issue additional units and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2.0% general partner interest.

The table below sets forth the number of common and subordinated units to be outstanding upon the closing of this offering and the number of unit equivalents represented by the 2.0% general partner interest and the aggregate distribution amounts payable on such units during the year following the closing of this offering at our minimum quarterly distribution rate of $ per unit per quarter ($ per unit on an annualized basis).

	Minimum Quarterly Distributions

	Number of Units	One Quarter	Annualized
Publicly held common units(1)		$	$
Common units held by Summit Investments(1)
Subordinated units held by Summit Investments
2.0% general partner interest

Total		$	$

(1): Assumes the underwriters do not exercise their option to purchase additional common units.

The subordination period generally will end if we have earned and paid at least $ on each outstanding common unit and subordinated unit and the corresponding distribution on our general partner's 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after , 2015. The subordination period will automatically terminate and all of the subordinated units will convert into an equal number of common units if we have earned and paid at least $ (150.0% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and the corresponding distribution on our general partner's 2.0% interest and the related distribution on the incentive distribution rights for any four consecutive quarter period ending on or after , 2013. Please read "Provisions of our Partnership Agreement Relating to Cash Distributions—Subordination Period."

If we do not pay the minimum quarterly distribution on our common units, our common unitholders will not be entitled to receive such payments in the future except during the subordination period. To the extent we have available cash in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common

units, we will use this excess available cash to pay any distribution arrearages related to prior quarters before any cash distribution is made to holders of subordinated units. Our subordinated units will not accrue arrearages for unpaid quarterly distributions or quarterly distributions less than the minimum quarterly distribution. Please read "Provisions of our Partnership Agreement Relating to Cash Distributions—Subordination Period."

Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. The actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. We will pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about the 1st of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. We will adjust the quarterly distribution for the period from the closing of this offering through September 30, 2012 based on the actual length of the period.

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our annualized minimum quarterly distribution of $ per unit for the twelve months ending June 30, 2013. In those sections, we present two tables, consisting of:

•: "Partnership Unaudited Historical As Adjusted Cash Available for Distribution," in which we present the amount of cash we would have had available for distribution on a historical as adjusted basis for the year ended December 31, 2011 and the twelve months ended March 31, 2012, derived from our historical consolidated financial statements that are included in this prospectus, as adjusted to give effect to the incremental general and administrative expenses associated with being a publicly traded partnership and our estimate of the amount of our historical maintenance capital expenditures; and
•: "Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2013," in which we demonstrate our ability to generate sufficient cash available for distribution for us to pay the minimum quarterly distribution on all units for the twelve months ending June 30, 2013.

Unaudited Historical As Adjusted Cash Available for Distribution for the Year Ended December 31, 2011 and the twelve months ended March 31, 2012

We acquired the Grand River system from Encana in October 2011 and, therefore, our historical consolidated financial statements that are included in this prospectus do not reflect a full year of financial results of the Grand River system. If we had completed our initial public offering and the related transactions contemplated by this prospectus on January 1, 2011, our historical as adjusted cash available for distribution for the year ended December 31, 2011, which includes two months of operations attributable to the Grand River system, would have been approximately $39.8 million. This amount would have been sufficient to pay the minimum quarterly distribution on all of the common units but only a cash distribution of $ per unit per quarter ($ per unit on an annualized basis), or approximately % of the minimum quarterly distribution, on our subordinated units for such period.

If we had completed our initial public offering and the related transactions contemplated by this prospectus on April 1, 2011, our historical as adjusted cash available for distribution for the twelve months ended March 31, 2012, which includes five months of operations attributable to the Grand River system, would have been approximately $49.3 million. This amount would have been sufficient to pay the minimum quarterly distribution on all of the common units but only a cash distribution of $ per unit per quarter ($ per unit on an annualized basis), or approximately % of the minimum quarterly distribution, on our subordinated units for such period.

Unaudited historical as adjusted cash available for distribution for the year ended December 31, 2011 and the twelve months ended March 31, 2012 includes incremental general and administrative expenses of approximately $2.5 million that we expect to incur as a result of becoming a publicly traded partnership. General and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the New York Stock Exchange, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer liability insurance costs and director compensation. These expenses are not reflected in the historical consolidated financial statements of our Predecessor. Our estimate of incremental general and administrative expenses is based upon currently available information.

The adjusted amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed on January 1, 2011 or April 1, 2011. In addition, cash available to pay distributions is primarily a cash accounting concept, while our historical consolidated financial statements have been prepared on an accrual basis. As a result, you should view the amount of historical as adjusted cash available for distribution only as a general indication of the amount of cash available to pay distributions that we might have generated had we completed this offering on January 1, 2011 or April 1, 2011.

The following table illustrates, on a historical as adjusted basis, for the year ended December 31, 2011 and the twelve months ended March 31, 2012, the amount of cash that would have been available for distribution to our unitholders, assuming that this offering and the related transactions contemplated by this prospectus had been consummated on January 1, 2011 or April 1, 2011. Each of the adjustments presented below is explained in the footnotes to such adjustments.

Partnership Unaudited Historical As Adjusted Cash Available for Distribution

	Twelve Months Ended March 31, 2012			Year Ended December 31, 2011

	(in millions)
Net Income:(1)	$	37.5		$	37.4
Add:
Depreciation and amortization expense		18.6			11.9
Amortization of favorable and unfavorable contracts(2)		0.1			0.3
Interest expense		7.2			3.1
Income tax expense(3)		0.8			0.7

EBITDA(4)	$	64.2		$	53.4
Add:
Change in deferred revenue related to MVCs(5)	$	1.8		$	—
Non-cash compensation expense(6)	$	2.7		$	3.4

Adjusted EBITDA(7)(8)	$	68.7		$	56.8
Less:
Incremental general and administrative expenses of being a publicly traded partnership(9)		2.5			2.5
Cash interest expense		4.2			2.5
Maintenance capital expenditures(10)		3.8			3.1
Expansion capital expenditures(10)		664.9			664.6
Interest on borrowings to fund expansion capital expenditures(10)		8.9			8.9

Add:
Borrowings to fund expansion capital expenditures(10)		664.9			664.6

Historical as Adjusted Cash Available for Distribution	$	49.3		$	39.8

Cash Distributions
Distributions per unit	$			$

Distributions to public common unitholders	$			$
Distributions to Summit Investments—common units
Distributions to Summit Investments—subordinated units
Distributions to our general partner
Total distributions	$			$

Shortfall	$			$

Percent of minimum quarterly distributions payable to common unitholders			%			%
Percent of minimum quarterly distributions payable to subordinated unitholders			%			%

(1): Includes $3.2 million and $3.4 million in non-recurring transaction costs recorded in the year ended December 31, 2011 and the twelve months ended March 31, 2012, respectively, incurred in connection with the acquisition of the Grand River system.
(2): The amortization of favorable and unfavorable contracts relates to gas gathering agreements that were deemed to be above or below market on September 3, 2009, the date of the acquisition of the DFW Midstream system, which are amortized 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.

(3): Represents the Texas franchise tax (applicable to income apportioned to Texas beginning January 1, 2007), which is classified as an income tax for reporting purposes.
(4): For a definition of EBITDA and a reconciliation of EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read "Selected Historical Financial and Operating Data—Non-GAAP Financial Measure."
(5): Reflects the net amount of all increases and decreases in deferred revenue for MVCs for the twelve months ended March 31, 2012. For GAAP accounting purposes, we are required to record cash shortfall payments relating to certain customer MVCs as deferred revenue until all contingencies or potential performance obligations associated with the shortfall payment volumes have either (1) been satisfied through the passage of time under the terms of the applicable MVC or (2) expired through the passage of time under the terms of the applicable natural gas gathering agreement. For the purpose of calculating our Cash Available for Distribution, we have assumed that any shortfall payments are recorded in Adjusted EBITDA in the period in which the cash shortfall payment is received.
(6): Represents $3.4 million and $2.7 million in non-cash compensation expense that was recorded in the year ended December 31, 2011 and the twelve months ended March 31, 2012, respectively, relative to profits interests held by certain members of management.
(7): Represents actual historical Adjusted EBITDA for the year ended December 31, 2011 and the twelve months ended March 31, 2012.
(8): For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read "Selected Historical Financial and Operating Data—Non-GAAP Financial Measure."
(9): Represents estimated cash expenses associated with being a publicly traded partnership, such as expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the New York Stock Exchange, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer liability insurance costs and director compensation.
(10): For the year ended December 31, 2011 and the twelve months ended March 31, 2012, our total capital expenditures were $667.7 million and $668.7 million, respectively. Approximately $590.0 million of the capital expenditures in 2011 were related to our acquisition of the Grand River system in October 2011. Historically, we did not make a distinction between maintenance and expansion capital expenditures, however for purposes of the presentation of Partnership Unaudited Historical As Adjusted Cash Available for Distribution, we have estimated that approximately $3.1 million and $3.8 million of these capital expenditures were maintenance capital expenditures for the year ended December 31, 2011 and the twelve months ended March 31, 2012, respectively. The balance of our capital expenditures for the period presented were assumed to have been expansion capital expenditures. We have included borrowings to offset our estimated expansion capital expenditures as well as incremental interest expense on these borrowings at an assumed interest rate of 8.0%, which is the interest rate on the promissory notes payable to our sponsors.

Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2013

We forecast that our estimated cash available for distribution for the twelve months ending June 30, 2013 will be approximately $85.9 million. This amount would exceed by $ million the amount needed to pay the total annualized minimum quarterly distribution of $ on all of our units for the twelve months ending June 30, 2013.

We have not historically made public projections as to future operations, earnings or other results of our business. However, our management has prepared the forecast of estimated cash available for distribution and related assumptions set forth below to supplement our historical consolidated financial statements in support of our belief that we will generate sufficient cash available for distribution to pay the aggregate annualized minimum quarterly distribution to all of our unitholders for the twelve months ending June 30, 2013. This forecast is a forward-looking statement and should be read together with the historical consolidated financial statements and the accompanying notes included elsewhere in this prospectus and "Management's Discussion and Analysis of Financial Condition and Results of Operations." The accompanying prospective financial information was not prepared with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management's knowledge and belief, the assumptions on which we base our belief that we will generate sufficient cash available for distribution to pay the aggregate annualized minimum quarterly distribution to all of our unitholders for the twelve months ending June 30, 2013. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. Neither our independent registered public accounting firm, nor any other independent accountants have compiled, examined, or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the prospective financial information. The reports of our independent registered public accounting firm included in this prospectus relate to our and our Predecessor's historical financial information, and those reports do not extend to the prospective financial information and should not be read to do so.

When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under "Risk Factors." Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate sufficient cash available for distribution to pay the total annualized minimum quarterly distribution to all of our unitholders for the twelve months ending June 30, 2013.

We are providing the forecast of estimated cash available for distribution and related assumptions set forth below to supplement our historical consolidated financial statements included elsewhere in this prospectus in support of our belief that we will have sufficient cash available for distribution to allow us to pay the total annualized minimum quarterly distribution to all of our unitholders and the corresponding distributions on our general partner's 2.0% interest for the twelve months ending June 30, 2013. Please read below under "—Assumptions and Considerations" for further information as to the assumptions we have made for the financial forecast.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. In light of this, the statement that we believe that we will have sufficient cash available for distribution to allow us to pay the total annualized minimum quarterly distribution to all of our unitholders for the twelve months ending June 30, 2013, should not be regarded as a representation by us, the underwriters or any other person that we will make such distribution. Therefore, you are cautioned not to place undue reliance on this information.

Estimated Cash Available for Distribution

	Twelve Months Ending June 30, 2013

	(in millions)
Revenues
Gathering services and other fees	$	141.7
Natural gas and condensate sales		12.7
Amortization of favorable and unfavorable contracts(1)		(1.5	)

Total revenues	$	152.9
Costs and Expenses
Operations and maintenance		49.4
General and administrative		21.0
Depreciation and amortization		32.9

Total costs and expenses		103.3
Interest expense		9.4
Income tax expense(2)		0.6

Net Income	$	39.6
Adjustments to reconcile net income to Estimated Adjusted EBITDA:
Add:
Depreciation and amortization expense		32.9
Amortization of favorable and unfavorable contracts(1)		1.5
Interest expense		9.4
Income tax expense		0.6

EBITDA(3)	$	84.0
Add:
Change in deferred revenue related to MVCs(4)	$	13.1
Non-cash compensation expense(5)	$	1.8

Estimated Adjusted EBITDA(6)	$	98.9
Adjustments to reconcile Estimated Adjusted EBITDA to Estimated Cash Available for Distribution:
Less:
Cash interest expense		7.8
Expansion capital expenditures		59.3
Maintenance capital expenditures		5.2
Add:
Borrowings to fund expansion capital expenditures		59.3

Estimated Cash Available for Distribution	$	85.9
Distributions to public common unitholders	$
Distributions to Summit Investments—common units
Distributions to Summit Investments—subordinated units
Distributions to our general partner
Total annualized minimum quarterly distributions	$
Excess of cash available for distribution over aggregate annualized minimum annual cash distributions	$

(1): The amortization of favorable and unfavorable contracts relates to gas gathering agreements that were deemed to be above or below market on September 3, 2009, the date of the acquisition of the DFW Midstream system, which are amortized 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): Represents the Texas franchise tax (applicable to income apportioned to Texas beginning January 1, 2007), which is classified as an income tax for reporting purposes.
(3): For a definition of EBITDA and a reconciliation of EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read "Selected Historical Financial and Operating Data—Non-GAAP Financial Measure."
(4): Reflects the estimated net amount of all increases and decreases in deferred revenue for MVCs over the forecast period. For GAAP accounting purposes, we are required to record cash shortfall payments relating to certain customer MVCs as deferred revenue until all contingencies or potential performance obligations associated with the shortfall payment volumes have either (1) been satisfied through the gathering of future volumes in excess of the applicable MVC or (2) expired through the passage of time under the terms of the applicable natural gas gathering agreement. For the purpose of calculating our Cash Available for Distribution, we have assumed that any shortfall payments are recorded in Adjusted EBITDA in the period in which the cash shortfall payment is received. In the forecast period, the $13.1 million of change in deferred revenue related to MVCs consists of: (1) $14.1 million of estimated increases to deferred revenue related to cash shortfall payments received from certain of our customers and (2) $1.0 million of estimated decreases to deferred revenue resulting from the expiration of MVC credits earned in prior periods.
(5): Represents $1.8 million in non-cash compensation expense expected to occur during the twelve months ending June 30, 2013.
(6): For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read "Selected Historical Financial and Operating Data—Non-GAAP Financial Measure."

Assumptions and Considerations

Set forth below are the material assumptions that we have made in order to demonstrate our ability to generate sufficient cash available for distribution to pay the total annualized minimum quarterly distribution to all unitholders for the twelve months ending June 30, 2013.

General Considerations

As discussed further below, a significant portion of the increase in cash available for distribution for the twelve months ending June 30, 2013 as compared to the year ended December 31, 2011 and the twelve months ended March 31, 2012 is attributable to additional revenues that we expect to generate under gas gathering agreements related to our Grand River system. Because we acquired the Grand River system in October 2011, revenues from these gas gathering agreements are not included in our historical results prior to November 2011.

Revenue

We estimate that we will generate revenue of $152.9 million for the twelve months ending June 30, 2013, compared to $103.6 million for the year ended December 31, 2011 and $120.2 million for the twelve months ended March 31, 2012. The significant increase in revenue for the forecast period as compared to the year ended December 31, 2011 and the twelve months ended March 31, 2012 is primarily attributable to the inclusion of our Grand River system for the entire forecast period as compared to just two months for the year ended December 31, 2011 and just five months for the twelve months ended March 31, 2012. Approximately 44% of our projected revenue is expected to be

generated from our Grand River system and approximately 56% is expected to be generated from our DFW Midstream system for the twelve month period ending June 30, 2013. Approximately 87% of our revenue is associated with fee-based gathering services that we provide to our customers. Approximately 8% of our revenue is associated with (i) the sale of physical natural gas that we retain from our DFW Midstream customers to offset our power expense associated with the operation of our electric-drive compression and (ii) the sale of condensate volumes that we collect on our Grand River system. We generate the remainder of our revenue by charging certain customers with respect to costs we incur on their behalf to deliver pipeline quality natural gas to third-party pipelines and costs we incur to operate electric-drive compression on the Grand River system.

•

Volumes. We estimate that we will gather an average of 914 MMcf/d for the twelve months ending June 30, 2013. This compares to our average daily throughput in the first quarter of 2012 of approximately 908 MMcf/d and an average of 428 MMcf/d for the year ended December 31, 2011 and 584 MMcf/d for the twelve months ended March 31, 2012. This expected increase in volumes in the forecast period as compared to the year ended December 31, 2011 and the twelve months ended March 31, 2012 is primarily due to our acquisition of the Grand River system in October 2011 and is partially offset by natural declines in production from existing wells on both of our gathering systems.

•: Grand River volumes. Our average daily throughput on the Grand River system in the first quarter of 2012 was approximately 593 MMcf/d. We expect throughput will average approximately 572 MMcf/d for the twelve months ending June 30, 2013, primarily based on (i) production schedules provided by certain of our customers and (ii) our assumption that our other customers will drill and connect new wells to offset the natural decline of existing wells connected to the Grand River system, thereby keeping throughput in the forecast period relatively flat with current throughput. Projected throughput for the twelve months ending June 30, 2013 compares to aggregate minimum volume commitments of 470 MMcf/d from our Grand River customers over the same time period and average daily throughput of 596 MMcf/d for the two months ended December 31, 2011 and 595 MMcf/d for the five months ended March 31, 2012.
•: DFW Midstream volumes. Our average daily throughput on the DFW Midstream system in the first quarter of 2012 was approximately 315 MMcf/d. We expect throughput on the DFW Midstream system will average approximately 342 MMcf/d for the twelve months ending June 30, 2013, primarily based on our assumption that in the aggregate, our customers' production will be more than sufficient to offset the natural decline of existing wells connected to the DFW Midstream system. Projected throughput for the twelve months ending June 30, 2013 compares to aggregate minimum volume commitments of 182 MMcf/d from our DFW Midstream customers over the same time period and average throughput of 329 MMcf/d for the year ended December 31, 2011 and 337 MMcf/d for the twelve months ended March 31, 2012.

•

Fees. We estimate that we will receive an average gathering fee of $0.40 per Mcf for the twelve months ending June 30, 2013, compared to $0.53 per Mcf for the year ended December 31, 2011 and $0.46 per Mcf for the twelve months ended March 31, 2012. Our calculation of the average gathering fee is based on an analysis of the projected volumes and fixed contractual fees (subject to contractual escalation in certain cases) under each of our gas gathering agreements. We expect our overall average gathering fee to be lower in the forecast period as compared to the year ended December 31, 2011 and the twelve months ended March 31, 2012 primarily as a result of the inclusion of our Grand River system, which generates a lower average gathering fee per Mcf than our DFW Midstream system, in the forecast period. All of our gathering fees are fixed and subject to the terms of the gas gathering agreements we have with each of our customers.

•: Grand River Fees. Our average gathering fees on the Grand River system for the year ended December 31, 2011 and the twelve months ended March 31, 2012 were $0.30 per Mcf and $0.28 per Mcf, respectively. We estimate that we will receive an average gathering fee on the Grand River system of $0.28 per Mcf for the twelve months ending June 30, 2013.
•: DFW Midstream Fees. Our average gathering fees on the DFW Midstream system for the year ended December 31, 2011 and the twelve months ended March 31, 2012 were $0.60 per Mcf and $0.59 per Mcf, respectively. We estimate that we will receive an average gathering fee on the DFW Midstream system of $0.60 per Mcf for the twelve months ending June 30, 2013.

•: Natural Gas and Condensate Sales. Approximately 8% of our projected revenue in the twelve months ending June 30, 2013 is associated with (i) the sale of physical natural gas that we retain from our DFW Midstream customers to offset our power expense and (ii) the sale of condensate volumes that we collect on our Grand River system. This projection is based on our assumption that we will sell the retained natural gas at Henry Hub pricing as of June 26, 2012, less a basis differential consistent with historical differentials, less contracted transportation costs, and that we will sell the condensate at the NYMEX crude oil strip price as of June 26, 2012, less a basis differential consistent with historical differentials. Fuel retainage volumes are projected according to specific terms embedded within all of the gas gathering agreements for our DFW Midstream customers. We assume that we will sell 8.6 MMBtu/d of natural gas at $3.07 per MMBtu for the twelve months ending June 30, 2013, compared to 10.8 MMBtu/d of natural gas at $3.60 per MMBtu for the year ended December 31, 2011 and 9.5 MMBtu/d of natural gas at $3.24 per MMBtu for the twelve months ended March 31, 2012. Condensate volumes are projected according to historical condensate yields based primarily on projected throughput on our Mamm Creek and South Parachute gathering assets. We assume that we will sell 112 Bbls/d of condensate at $70 per Bbl for the twelve months ending June 30, 2013, compared to 20 Bbls/d of condensate at $85 per Bbl for the year ended December 31, 2011 and 60 Bbls/d of condensate at $88 per Bbl for the twelve months ended March 31, 2012.
•: Sensitivity Analysis. The actual volume of natural gas that we gather on our systems will influence whether the amount of cash available for distribution for the twelve months ending June 30, 2013 is above or below our forecast. If the actual volume of natural gas we gather on our systems is below our forecast, we may not have sufficient cash available to pay the aggregate annualized minimum quarterly distribution to all of our unitholders for the forecast period. If the actual volume of natural gas we gather on our systems for the twelve months ending June 30, 2013 was 10% lower than our forecast, we would have sufficient cash available to pay the full distribution to holders of our common units and only % of the aggregate annualized minimum quarterly distribution to the holders of our subordinated units.

Operating and Maintenance Expenses

Our primary operating and maintenance expenses include labor costs, compression costs, ad valorem and property taxes, utilities and contract services. We estimate that we will incur operating and maintenance expenses of $49.4 million for the twelve months ending June 30, 2013, compared to operating and maintenance expenses of $29.9 million for the year ended December 31, 2011 and $34.7 million for the twelve months ended March 31, 2012. Included in these amounts is compression expense that we incur to operate our electric-drive compression assets on our DFW Midstream system, which varies with (i) our power consumption, which is correlated to the actual throughput on our DFW Midstream system, and (ii) the cost of power. We estimate that we will incur compression costs of $12.2 million, or $0.10 per Mcf, for the twelve months ending June 30, 2013, compared to compression costs of $13.4 million, or $0.11 per Mcf, for the year ended December 31, 2011 and $13.1 million, or $0.11 per Mcf, for the twelve months ended March 31, 2012. Under our gas gathering agreements with

our DFW Midstream customers, we physically retain a certain percentage of each customer's throughput that we then sell to offset the power costs we incur. Under our gas gathering agreements with our Grand River customers, we either (i) consume physical gas on the system to operate our gas-fired compression assets or (ii) charge our customers for the power costs we incur to operate our electric-drive compression assets. Excluding our total compression costs, we estimate that we will incur operating and maintenance expenses of $37.1 million, or $0.11 per Mcf, for the twelve months ending June 30, 2013, compared to operating and maintenance expenses of $16.5 million, or $0.11 per Mcf, for the year ended December 31, 2011 and $21.6 million, or $0.10 per Mcf, for the twelve months ended March 31, 2012. Increased aggregate operating and maintenance expenses for the twelve months ending June 30, 2013 are primarily related to the acquisition of the Grand River system in October 2011 and the additional DFW Midstream operations personnel that were hired during the year ended December 31, 2011 and the twelve months ended March 31, 2012.

We expect that operating and maintenance expenses will increase in the aggregate, primarily as a result of higher compression expenses, as throughput increases across our gathering systems. However, we expect operating and maintenance expenses net of compression costs on a dollar per Mcf basis to decline as throughput on our systems increases at a higher rate than our non-compression operating and maintenance expenses and our compression costs are passed on to our customers or offset by our sale of physical natural gas that we retain from our DFW Midstream customers, as applicable.

General and Administrative Expenses

Our general and administrative expenses will primarily consist of general and administrative expenses that we incur and payments that we make to our general partner in exchange for the provision of general and administrative services, including approximately $2.5 million of expenses we expect to incur as a result of becoming a publicly traded partnership. General and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the New York Stock Exchange, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer liability insurance costs and director compensation.

We expect our general and administrative expenses to total approximately $21.0 million for the twelve months ending June 30, 2013, compared to general and administrative expenses of $17.5 million for the year ended December 31, 2011 and $18.0 million for the twelve months ended March 31, 2012. The primary drivers of our anticipated increase in general and administrative expenses are our acquisition of the Grand River system in October 2011 including the associated expense of hiring our Grand River asset management and other corporate personnel, and $2.5 million of incremental expenses related to being a publicly traded partnership, partially offset by an approximately $1.6 million reduction in non-cash compensation expenses. Non-cash compensation expense totaled $3.4 million in the twelve months ended December 31, 2011 and included two one-time adjustments totaling $2.4 million, approximately $1.4 million of which was associated with a modification to the DFW Midstream Class B rate of return payout hurdle and approximately $1.0 million of which was associated with non-cash compensation expense for years prior to 2011. As a result, the $1.8 million of non-cash compensation expense projected for the twelve months ending June 30, 2013 is higher than the $1.0 million of normalized 2011 non-cash compensation expense in the twelve months ended December 31, 2011 due to compensatory awards issued in April 2011, October 2011, and January 2012.

Depreciation and Amortization Expense

We estimate that depreciation and amortization expense for the twelve months ending June 30, 2013 will be $32.9 million, compared to $11.9 million for the year ended December 31, 2011 and $18.6 million for the twelve months ended March 31, 2012. Estimated depreciation and amortization

expense reflects management's estimates, which are based on consistent average depreciable asset lives and depreciation methodologies. The increase in depreciation and amortization expense is primarily attributable to the inclusion of a full year of depreciation on our Grand River assets and expected capital investments on both the DFW Midstream system and the Grand River system.

Capital Expenditures

We estimate that total capital expenditures for the twelve months ending June 30, 2013 will be $64.5 million, compared to $667.7 million for the year ended December 31, 2011 and $668.7 million for the twelve months ended March 31, 2012. Approximately $590.0 million of our capital expenditures for the year ended December 31, 2011 and the twelve months ended March 31, 2012 were related to the acquisition of the Grand River system in October 2011. Capital expenditures attributable to the DFW Midstream system and Grand River system in November and December 2011 accounted for the remainder. Substantially all of our projected capital expenditures are associated with expanding our existing Grand River and DFW Midstream systems. We estimate that total capital expenditures on our Grand River system will be approximately $30.7 million for the twelve months ending June 30, 2013, which will account for approximately 48% of our total capital expenditures during the forecast period, with the DFW Midstream system accounting for the remainder.

•

Maintenance Capital Expenditures. Historically, we did not make a distinction between maintenance and expansion capital expenditures. We estimate that we will spend $5.2 million for maintenance capital expenditures for the twelve months ending June 30, 2013. The types of maintenance capital expenditures that we expect to incur include expenditures to connect additional pad sites to maintain current volumes and expenditures to replace system components and equipment that have suffered significant wear and tear, become obsolete or approached the end of their useful lives. It has been customary in the regions in which we operate for producers to bear the cost of connecting individual wells to our pad site meters or central receipt points. In areas where multiple wells are located on a single pad site, such as on the DFW Midstream system, individual wells are connected to our measurement meter on the pad site, which is in turn connected to our gathering pipeline system. In other areas without multiple well pad sites, such as parts of the Grand River system, individual wells are connected to our nearest central receipt point meter, which in turn is connected to our pipeline gathering system.

•

Expansion Capital Expenditures. We estimate that our expansion capital expenditures for the twelve months ending June 30, 2013 will total $59.3 million, of which approximately $28.2 million are attributable to the Grand River system and approximately $31.0 million are attributable to the DFW Midstream system. Although we expect that these expenditures will increase throughput over time, we have not assumed any additional volumes during the forecast period related to these expenditures.

•: Grand River system.The majority of our projected expansion capital expenditures on the Grand River system are associated with looping certain sections of pipeline in order to increase system capacity, optimize throughput hydraulics and operating pressures and increase our pad site connections for ongoing low-pressure Mesaverde formation drilling activities.
•: DFW Midstream system.The substantial majority of the expansion capital expenditures associated with the DFW Midstream system will be to construct new low-pressure pipeline laterals to connect additional identified pad sites for our existing customers, install additional compression assets and complete the construction of several looping pipelines on the DFW Midstream system to increase system capacity to over 450 MMcf/d and optimize throughput hydraulics and operating pressures. We are also forecasting expansion capital expenditures during the twelve months ending June 30, 2013 of approximately $11.9 million

associated with five pad sites adjacent to the DFW Midstream system for our new customer, Beacon E&P.

Financing

•

Amended and Restated Revolving Credit Facility. Our amended and restated credit agreement contains affirmative and negative covenants customary for credit facilities of this size and nature, that, among other things, 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 be less 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 (or 5.50 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 to customary 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 transactions of such types;
•: pay dividends or make cash distributions, provided that we may make quarterly distributions to our unitholders, so long as no default or event of default under the amended and restated credit agreement then exists or would result therefrom, and subject to compliance (on both a pro forma basis and after giving effect to the making of such distribution) with our financial performance covenants 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 swap agreements 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.

Repayments of principal under our amended and restated credit facility are not reflected as reductions in estimated cash available for distribution.

•: Cash and Liquidity. At the closing of this offering, we expect to have $ million of capacity under our amended and restated revolving credit facility after using a portion of the net proceeds of this offering to repay approximately $ million currently outstanding under our amended and restated revolving credit facility. Please read "Use of Proceeds." At the closing of this offering, we expect to have outstanding indebtedness of approximately $ million and a total leverage ratio of approximately 2.0x, which we believe will provide us with sufficient liquidity to fund our anticipated expansion capital expenditures during the forecast period. We intend to fund our forecasted maintenance capital expenditures with operating cash flow. We intend to refinance debt as it comes due, and because our credit facility does not require any principal payments until the facility matures in 2016, we have assumed no principal repayments during the forecast period.
•: Interest Expense. We estimate that our interest expense excluding the effects of amortization of deferred loan costs for the twelve months ending June 30, 2013 will be approximately $7.8 million, compared to $2.5 million for the year ended December 31, 2011 and $6.5 million for the twelve months ended March 31, 2012. Our projected interest expense is based on an assumed average outstanding debt balance of $201.5 million under our amended and restated

revolving credit facility during the forecasted period, including borrowings to finance our projected expansion capital expenditures, with an assumed weighted average interest rate of % and a commitment fee of % that we expect to pay on the undrawn portion of the revolving credit facility. We have assumed no interest income with respect to the cash that we maintain on our balance sheet during the forecast period.

Regulatory, Industry and Economic Factors

Our forecast for the twelve months ending June 30, 2013 is based on the following significant assumptions related to regulatory, industry and economic factors:

•: There will not be any new federal, state or local regulation of the midstream energy sector, or any new interpretation of existing regulations, that will be materially adverse to our business.
•: There will not be any major adverse change in the midstream energy sector, commodity prices or in market, insurance or general economic conditions.
•: There will not be any material accidents, weather-related incidents, unscheduled downtime or similar unanticipated events with respect to our facilities or those of third parties on which we depend.
•: We will not make any acquisitions or other significant expansion capital expenditures (other than as described above).

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General

Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending , 2012, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the closing of the offering through , 2012 based on the actual length of the period.

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 debt service requirements);
•: comply with applicable law, any of our debt instruments or other agreements; and
•: provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such 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 the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our partnership agreement, working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners, and with the intent of the borrower to repay such borrowings within 12 months with funds other than from additional working capital borrowings. The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures (as described below) and thus reduce operating surplus when repayments are made. However, if working capital borrowings, which increase operating surplus, are not repaid during the 12-month period following the borrowing, they will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowings are in fact repaid, they will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

Intent to Distribute the Minimum Quarterly Distribution

We intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $ per unit, or $ on an annualized basis, to the extent we have

sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Amended and Restated Revolving Credit Facility" for a discussion of the restrictions included in our amended and restated revolving credit facility that may restrict our ability to make distributions.

General Partner Interest and Incentive Distribution Rights

Initially, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. Our general partner's initial 2.0% interest in our distributions will be reduced if we issue additional limited partner units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest.

Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from operating surplus (as defined below) in excess of $ 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 that our general partner maintains its general partner interest at 2.0%. The maximum distribution of 50.0% does not include any distributions that our general partner may receive on any limited partner units that it owns. Please read "—General Partner Interest and Incentive Distribution Rights" for additional information.

Operating Surplus and Capital Surplus

General

All cash distributed to unitholders will be characterized as either being paid from "operating surplus" or "capital surplus." We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.

Operating Surplus

We define operating surplus as:

•: $ million (as described below);plus
•: all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below), provided that cash receipts from the termination of a commodity hedge or interest rate hedge prior to its specified termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge or interest rate hedge;plus
•: working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for that quarter;plus
•: cash distributions (including incremental distributions on incentive distribution rights) paid on equity issued, other than equity issued in this offering, to finance all or a portion of the construction, acquisition, development or improvement of a capital improvement or replacement of a capital asset (such as equipment or facilities) in respect of the period beginning on the date

that we enter into a binding obligation to commence the construction, acquisition, development or improvement of a capital improvement or replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset commences commercial service and the date that it is abandoned or disposed of;plus

•: cash distributions (including incremental distributions on incentive distribution rights) paid on equity issued, other than equity issued in this offering, to pay the construction-period interest on debt incurred, or to pay construction-period distributions on equity issued, to finance the capital improvements or capital assets referred to above;less
•: all of our operating expenditures (as defined below) after the closing of this offering;less
•: the amount of cash reserves established by our general partner to provide funds for future operating expenditures;less
•: all working capital borrowings not repaid within 12 months after having been incurred, or repaid within such 12-month period with the proceeds of additional working capital borrowings;less
•: any cash loss realized on disposition of an investment capital expenditure.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by operations. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $ �� million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

We define interim capital transactions as (i) borrowings, refinancings or refundings of indebtedness (other than working capital borrowings and items purchased on open account in the ordinary course of business) and sales of debt securities, (ii) sales of equity securities, (iii) sales or other dispositions of assets, other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and sales or other dispositions of assets as part of ordinary course asset retirements or replacements, (iv) the termination of commodity hedge contracts or interest rate hedge contracts prior to the termination date specified therein (provided that cash receipts from any such termination will be included in operating surplus in equal quarterly installments over the remaining scheduled life of the contract), (v) capital contributions received and (vi) corporate reorganizations or restructurings.

We define operating expenditures as all of our cash expenditures, including, but not limited to, taxes, reimbursements of expenses to our general partner and its affiliates, interest payments, payments made in the ordinary course of business under interest rate hedge contracts and commodity hedge contracts (provided that (i) with respect to amounts paid in connection with the initial purchase of an interest rate hedge contract or a commodity hedge contract, such amounts will be amortized over the life of the applicable interest rate hedge contract or commodity hedge contract and (ii) payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract), director and officer compensation, repayment of working

capital borrowings and non-pro rata repurchases of our units;provided,however, that operating expenditures will not include:

•: repayments of working capital borrowings where such borrowings have previously been deemed to have been repaid (as described above);
•: payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than working capital borrowings;
•: expansion capital expenditures;
•: investment capital expenditures;
•: payment of transaction expenses (including, but not limited to, taxes) relating to interim capital transactions;
•: distributions to our partners; or
•: non-pro rata purchases of any class of our units made with the proceeds of an interim capital transaction.

Capital Surplus

Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, except as described above, capital surplus would generally be generated by:

•: borrowings other than working capital borrowings;
•: sales of our equity and debt securities; and
•: sales or other dispositions of assets, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of ordinary course retirement or replacement of assets.

Characterization of Cash Distributions

Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

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 operating income or operating capacity over the long term. We expect that a primary component of maintenance capital expenditures will include expenditures to connect additional wells to our gathering systems to offset natural declines in production over time and for routine equipment and pipeline maintenance or replacement due to obsolescence. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of the construction or development of a replacement asset that is paid in respect of the period that begins when we enter into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to

occur of the date that any such replacement asset commences commercial service and the date that it is abandoned or disposed of.

Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. Expansion capital expenditures include interest payments (and related fees) on debt incurred and issued to finance the construction of such capital improvement and paid in respect of the period beginning on the date that we enter into a binding obligation to commence construction of the capital improvement and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is abandoned or disposed of. Examples of expansion capital expenditures include the acquisition of equipment, or the construction, development or acquisition of additional pipeline or treating capacity or new compression capacity, to the extent such capital expenditures are expected to expand our long-term operating capacity or operating income.

Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of facilities that are in excess of the maintenance of our existing operating capacity or operating income, but that are not expected to expand, our operating capacity or operating income over the long-term.

Capital expenditures that are made in part for maintenance capital purposes, expansion capital purposes and/or investment capital purposes will be allocated as maintenance capital expenditures, expansion capital expenditures or investment capital expenditures by our general partner.

Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $ per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed "subordinated" because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

Subordination Period

Except as described below, the subordination period will begin on the closing date of this offering and will extend until the first business day of any quarter beginning after , 2015, that each of the following tests are met:

•: distributions of available cash from operating surplus on each of the outstanding common units and subordinated units and the related distribution on the general partner interest equaled or

exceeded $ (the annualized minimum quarterly distribution) for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

•: the adjusted operating surplus (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded (i) the sum of $ (the annualized minimum quarterly distribution) on all of the outstanding common and subordinated units during those periods on a fully diluted weighted average basis and (ii) the corresponding distribution on our 2.0% general partner interest; and
•: there are no arrearages in payment of the minimum quarterly distribution on the common units.

Early Termination of Subordination Period

Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day of any quarter beginning after , 2013, that each of the following tests are met:

•: distributions of available cash from operating surplus on each of the outstanding common units and subordinated units and the related distribution on the general partner interest equaled or exceeded $ (150.0% of the annualized minimum quarterly distribution), plus the related distributions on the incentive distribution rights, for the four-quarter period immediately preceding that date;
•: the adjusted operating surplus (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (i) $ (150.0% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units during that period on a fully diluted weighted average basis and (ii) the distributions made on our 2.0% general partner interest and the incentive distribution rights; and
•: there are no arrearages in payment of the minimum quarterly distributions on the common units.

Expiration of the Subordination Period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and no units held by our general partner and its affiliates are voted in favor of such removal:

•: the subordination period will end and each subordinated unit will immediately and automatically convert into one common unit;
•: any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
•: our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Definition of Adjusted Operating Surplus

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash established in prior periods. Adjusted operating surplus for a period consists of:

•: operating surplus generated with respect to that period (excluding any amounts attributable to the item described in the first bullet point under the caption "—Operating Surplus and Capital Surplus—Operating Surplus" above);less
•: any net increase in working capital borrowings with respect to that period;less
•: any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period;plus
•: any net decrease in working capital borrowings with respect to that period;plus
•: any net decrease made in subsequent periods to cash reserves for operating expenditures initially established with respect to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods pursuant to the third bullet point above;plus
•: any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Distributions of Available Cash from Operating Surplus during the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

•: first, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
•: second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;
•: third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
•: thereafter, in the manner described in "—General Partner Interest and Incentive Distribution Rights" below.

The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

Distributions of Available Cash from Operating Surplus after the Subordination Period

We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

•: first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
•: thereafter, in the manner described in "—General Partner Interest and Incentive Distribution Rights" below.

The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

General Partner Interest and Incentive Distribution Rights

Our partnership agreement provides that our general partner initially will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest if we issue additional units. Our general partner's 2.0% interest, and the percentage of our cash distributions to which it is entitled from such 2.0% interest, will be proportionately reduced if we issue additional units in the future (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest. Our partnership agreement does not require that our general partner fund its capital contribution with cash. It may instead fund its capital contribution by the contribution to us of common units or other property.

Incentive distribution rights represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

The following discussion assumes that our general partner maintains its 2.0% general partner interest, that there are no arrearages on common units and that our general partner continues to own the incentive distribution rights.

If for any quarter:

•: we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and
•: we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:

•: first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives a total of $ per unit for that quarter (the "first target distribution");
•: second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $ per unit for that quarter (the "second target distribution");
•: third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives a total of $ per unit for that quarter (the "third target distribution"); and
•: thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under "Marginal Percentage Interest in Distributions" are the percentage interests of

our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution Per Unit Target Amount." The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% 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 common units.

		Marginal Percentage Interest in Distributions

	Total Quarterly Distribution Per Unit Target Amount	Unitholders			General Partner
Minimum Quarterly Distribution	$		98.0	%		2.0	%
First Target Distribution	up to $		98.0	%		2.0	%
Second Target Distribution	above $up to $		85.0	%		15.0	%
Third Target Distribution	above $up to $		75.0	%		25.0	%
Thereafter	above $		50.0	%		50.0	%

General Partner's Right to Reset Incentive Distribution Levels

Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner transfers all or a portion of our incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made. Our general partner's right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the Conflicts Committee, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the four consecutive fiscal quarters immediately preceding such time and the amount of each such distribution did not exceed adjusted operating surplus for such quarter, respectively. If our general partner and its affiliates are not the holders of a majority of the incentive distribution rights at the time an election is made to reset the minimum quarterly distribution amount and the target distribution levels, then the proposed reset will be subject to the prior written concurrence of the general partner that the conditions described above have been satisfied. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units and general partner units based on a predetermined

formula described below that takes into account the "cash parity" value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters immediately preceding the reset event as compared to the average cash distributions per common unit during that two-quarter period. Our general partner will be issued the number of general partner units necessary to maintain our general partner's interest in us immediately prior to the reset election.

The number of common units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average aggregate amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the aggregate amount of cash distributed per common unit during each of these two quarters.

Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the "reset minimum quarterly distribution") and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

•: first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives an amount equal to 115.0% of the reset minimum quarterly distribution for that quarter;
•: second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives an amount per unit equal to 125.0% of the reset minimum quarterly distribution for the quarter;
•: third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the quarter; and
•: thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels

based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $ .

		Marginal Percentage Interest In Distributions

	Quarterly Distribution per Unit Prior to Reset	Unitholders			2% General Partner Interest			Incentive Distribution Rights			Quarterly Distributions per Unit Following Hypothetical Reset
Minimum Quarterly Distribution	$		98.0	%		2.0	%				$
First Target Distribution	up to $		98.0	%		2.0	%				up to $ (1)
Second Target Distribution	above $up to $		85.0	%		2.0	%		13.0	%	above $ (1), up to $ (2)
Third Target Distribution	above $up to $		75.0	%		2.0	%		23.0	%	above $ (2), up to $ (3)
Thereafter	above $		50.0	%		2.0	%		48.0	%	above $ (3)

(1): This amount is 115.0% of the hypothetical reset minimum quarterly distribution.
(2): This amount is 125.0% of the hypothetical reset minimum quarterly distribution.
(3): This amount is 150.0% of the hypothetical reset minimum quarterly distribution.

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, based on an average of the amounts distributed each quarter for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be common units outstanding, our general partner has maintained its 2.0% general partner interest and the average distribution to each common unit would be $ for the two quarters prior to the reset.

			Cash Distribution To General Partner Prior To Reset

		Cash Distributions to Common Unitholders Prior to Reset	Cash Distribution To General Partner Prior To Reset
	Quarterly Distribution per Unit Prior to Reset	Cash Distributions to Common Unitholders Prior to Reset	2% General Partner Interest	Incentive Distribution Rights	Total	Total Distributions
Minimum Quarterly Distribution	$
First Target Distribution	up to $
Second Target Distribution	above $up to $
Third Target Distribution	above $up to $
Thereafter	above $

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, with respect to the quarter in which the reset occurs. The table reflects that, as a result of the reset, there would be common units outstanding, our general partner's 2.0% interest has been maintained, and the average distribution to each common unit would be $ . The number of common units to be issued to our general partner upon the reset was calculated by dividing (i) the

average of the amounts received by our general partner in respect of its incentive distribution rights for the two quarters prior to the reset as shown in the table above, or $ , by (ii) the average available cash distributed on each common unit for the two quarters prior to the reset as shown in the table above, or $ .

			Cash Distribution To General Partner After Reset

		Cash Distributions to Common Unitholders After Reset	Cash Distribution To General Partner After Reset
	Quarterly Distribution per Unit After Reset	Cash Distributions to Common Unitholders After Reset	2% General Partner Interest	Incentive Distribution Rights	Total	Total Distributions
Minimum Quarterly Distribution	$
First Target Distribution	up to $
Second Target Distribution	above $up to $
Third Target Distribution	above $up to $
Thereafter	above $

Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the immediately preceding four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made

We will make distributions of available cash from capital surplus, if any, in the following manner:

•: first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price in this offering;
•: second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and
•: thereafter, as if they were from operating surplus.

The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

Effect of a Distribution from Capital Surplus

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the "unrecovered initial unit price." Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution and target distribution levels after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to

convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50.0% being paid to the unitholders, pro rata, and 50.0% to our general partner. The percentage interests shown for our general partner include its 2.0% general partner interest and assume that our general partner has not transferred the incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

•: the minimum quarterly distribution;
•: target distribution levels;
•: the unrecovered initial unit price;
•: the number of general partner units comprising the general partner interest; and
•: the per unit arrearage in payment of the minimum quarterly distribution on the common units.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level, and each subordinated unit would be split into two common units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) plus our general partner's estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated

units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

Manner of Adjustments for Gain

The manner of the adjustment for gain is set forth in our partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to our partners in the following manner:

•: first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;
•: second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;
•: third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;
•: fourth, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence;less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98.0% to the unitholders, pro rata, and 2.0% to our general partner, for each quarter of our existence;
•: fifth, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence;less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to our general partner for each quarter of our existence;
•: sixth, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence;less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75.0% to the unitholders, pro rata, and 25.0% to our general partner for each quarter of our existence;
•: thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

The percentages set forth above are based on the assumption that our general partner has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the fourth bullet point above will no longer be applicable.

Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our general partner and unitholders in the following manner:

•: first, 98.0% to the holders of subordinated units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;
•: second, 98.0% to the holders of common units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and
•: thereafter, 100.0% to our general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Adjustments to Capital Accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the partners' capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made. In contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our general partner based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders' capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

The following table presents as of the dates and for the periods indicated the selected historical consolidated financial and operating data of our Predecessor. On September 3, 2009, we acquired a controlling interest in DFW Midstream Services LLC, which we refer to as our Initial Predecessor for the period prior to such date. We use the term Summit Midstream Predecessor to describe our Predecessor's operations after September 3, 2009. We acquired the Grand River system on October 27, 2011 and we have included its financial results in the financial statements of Summit Midstream Predecessor since the date of acquisition.

The selected historical consolidated financial data presented as of March 31, 2012 and for the three months ended March 31, 2012 and March 31, 2011 are derived from our unaudited historical condensed financial statements included elsewhere in this prospectus. The selected historical consolidated financial data presented as of December 31, 2011 and December 31, 2010 and for the period from September 3, 2009 to December 31, 2009, for the year ended December 31, 2011 and the year ended December 31, 2010 have been derived from the audited historical consolidated financial statements of Summit Midstream Predecessor included elsewhere in this prospectus. The selected historical balance sheet data as of December 31, 2009 are derived from the audited historical financial statement of Summit Midstream Predecessor that are not included in this prospectus. The selected historical financial data for the period from January 1, 2009 to September 3, 2009 are derived from the audited historical financial statements of our Initial Predecessor included elsewhere in this prospectus. We acquired our initial assets from Energy Future Holdings Corp. and Chesapeake effective as of September 3, 2009.

The following table presents the non-GAAP financial measures of EBITDA and Adjusted EBITDA, which we use in our business as measures of performance and liquidity. We define EBITDA as net income:

•

Plus:

•: interest expense;
•: income tax expense; and
•: depreciation and amortization expense.

•

Less:

•: interest income; and
•: income tax benefit.

We define Adjusted EBITDA as EBITDA:

•

Plus:

•: non-cash equity compensation; and
•: deferred revenue related to MVCs.

For a reconciliation to our most directly comparable financial measures calculated and presented in accordance with GAAP, please read "—Non-GAAP Financial Measure" on page 93.



	Summit Midstream Predecessor
	Summit Midstream Predecessor															Initial Predecessor
	Three Months Ended March 31,															Initial Predecessor
	Three Months Ended March 31,						Year Ended December 31,						Period from September 3, 2009 to December 31, 2009			Period from January 1, 2009 to September 3, 2009
	2012			2011			2011			2010			Period from September 3, 2009 to December 31, 2009			Period from January 1, 2009 to September 3, 2009
	(in thousands, except for volume and price amounts)
Statement of Operations Data:
Revenue:
Gathering services and other fees	$	31,918		$	17,128		$	91,421		$	29,358		$	1,714		$	1,910
Natural gas and condensate sales		3,731			2,117			12,439			2,533			—			—
Amortization of favorable and unfavorable contracts(1)		134			(70	)		(308	)		(215	)		19			—

Total revenue	$	35,783		$	19,175		$	103,552		$	31,676		$	1,733		$	1,910
Costs and expenses:
Operations and maintenance		10,989			6,148			29,855			9,503			1,147			1,010
General and administrative		4,412			3,843			17,476			10,035			2,939			600
Transaction costs		193			—			3,166			—			3,921			—
Depreciation and amortization		8,290			1,605			11,915			3,874			343			882

Total costs and expenses		23,884			11,596			62,412			23,412			8,350			2,492

Interest (expense) income, net		(4,173	)		5			(3,042	)		32			18			(247	)
Income tax expense		(139	)		(73	)		(695	)		(124	)		(7	)		(8	)

Net income (loss)	$	7,587		$	7,511		$	37,403		$	8,172		$	(6,606	)	$	(837	)

Pro forma earnings per common unit(2)
Pro forma weighted average common units outstanding(2)
Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	16,605		$	8,855		$	39,942		$	9,553		$	(6,232	)	$	595
Investing activities		(20,577	)		(19,606	)		(667,710	)		(153,719	)		(64,415	)		(40,777	)
Financing activities		(579	)		8,000			633,809			114,132			110,102			40,182
Balance Sheet Data (at period end):
Cash and cash equivalents	$	10,911					$	15,462		$	9,421		$	39,455
Trade accounts receivable		30,997						27,476			10,238			1,373
Property, plant, and equipment, net		652,732						642,552			277,765			140,704
Total assets		1,032,164						1,026,498			340,095			215,982
Total debt(3)		353,940						349,893			—			—
Other Financial Data:
EBITDA(4)	$	20,055		$	9,254		$	53,363		$	12,353		$	(6,293	)	$	300
Adjusted EBITDA(4)	$	23,699		$	10,468		$	56,803		$	12,353		$	(6,293	)	$	300
Capital expenditures		20,577			19,606			78,248			153,719			19,519			40,777
Acquisition expenditures(5)		—			—			589,462			—			44,896			—
Operating data:
Average throughput (MMcf/d)		908.4			285.2			428.0			134.3			15.4			15.7

(1): The amortization of favorable and unfavorable contracts relates to gas gathering agreements that were deemed to be above or below market on September 3, 2009, the date of the acquisition of the DFW Midstream system, which are amortized 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): The pro forma earnings per common unit gives effect to the recapitalization transactions as of December 31, 2011 and March 31, 2012 and the additional number of common units issued in this offering (at an assumed offering price of $ per unit) necessary to pay the portion of the distribution to Summit Investments described in "Use of Proceeds" that will be funded from the proceeds of this offering that exceeds net income for the year ended December 31, 2011 and the three months ended March 31, 2012. For a description of the calculation of pro forma earnings attributable to common and subordinated units, please read Note 1 to our audited consolidated financial statements and Note 1 to our unaudited consolidated financial statements included elsewhere in this prospectus. For a reconciliation of historical weighted average common units used in the computation of limited partners' net income (loss) per common unit and pro forma weighted average common and subordinated units outstanding, please read Note 1 to our audited consolidated financial statements and Note 1 to our unaudited condensed consolidated financial statements included elsewhere in this prospectus.
(3): Includes $202.9 million and $206.9 million of debt outstanding under our promissory notes payable to our sponsors at December 31, 2011 and March 31, 2012. On July 2, 2012, the outstanding balance under the notes was paid in full.
(4): EBITDA and Adjusted EBITDA for the three months ended March 31, 2012 and for the year ended December 31, 2011 include $0.2 million and $3.2 million, respectively, in transaction costs related to our acquisition of Grand River. EBITDA and Adjusted EBITDA for the year ended December 31, 2010 include $1.8 million in settlement expenses related to a dispute with a contractor at the DFW Midstream system. EBITDA and Adjusted EBITDA for the 2009 Summit Midstream Predecessor Period include transaction costs of $3.9 million primarily related to the acquisition of the DFW Midstream system in September 2009. These unusual and non-recurring expenses were included in the calculations of EBITDA and Adjusted EBITDA and were settled in cash.
(5): Reflects the acquisition of certain assets of the DFW Midstream system from Chesapeake in September 2009 and the acquisition of the Grand River System in October 2011.

Non-GAAP Financial Measure

We include in this prospectus the non-GAAP financial measures of EBITDA and Adjusted EBITDA. We provide a reconciliation of this non-GAAP financial measure to their most directly comparable financial measures as calculated and presented in accordance with GAAP.

EBITDA

We define EBITDA as net income (loss):

•

Plus:

•: interest expense;
•: income tax expense; and
•: depreciation and amortization expense.

•

Less:

•: interest income; and
•: income tax benefit.

We define Adjusted EBITDA as EBITDA:

•

Plus:

•: non-cash equity compensation; and
•: deferred revenue related to MVCs.

EBITDA and Adjusted EBITDA are used as supplemental financial measures by management and by external users of our financial statements, such as investors and lenders, to assess:

•: the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
•: the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unitholders and general partner;
•: our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and
•: the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

The GAAP measures most directly comparable to EBITDA and Adjusted EBITDA are net cash flows provided by operating activities and net income. Our non-GAAP financial measures of EBITDA and Adjusted EBITDA should not be considered as an alternative to net income or cash flows from operating activities. You should not consider EBITDA and Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. EBITDA and Adjusted EBITDA have limitations as analytical tools and should not be considered as alternatives to, or more meaningful than, performance measures calculated in accordance with GAAP. Some of these limitations are:

•: certain items excluded from EBITDA and Adjusted EBITDA are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure;
•: EBITDA and Adjusted EBITDA do not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;
•: EBITDA and Adjusted EBITDA do not reflect changes in, or cash requirements for, our working capital needs;
•: although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA and Adjusted EBITDA do not reflect any cash requirements for such replacements; and
•: our computations of EBITDA and Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

Management compensates for the limitations of EBITDA and Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management's decision-making process.

The following table presents a reconciliation of Adjusted EBITDA to net income and net cash flows provided by operating activities for each of the periods indicated:



	Summit Midstream Predecessor												Initial Predecessor
	Three Months Ended March 31,					Year Ended December 31,							Initial Predecessor
	Three Months Ended March 31,					Year Ended December 31,				Period from September 3, 2009 to December 31, 2009			Period from January 1, 2009 to September 3, 2009
	2012			2011		2011		2010		Period from September 3, 2009 to December 31, 2009			Period from January 1, 2009 to September 3, 2009
	(in thousands, except for volume and price amounts)
Reconciliation of EBITDA and Adjusted EBITDA to Net Income (Loss)
Net Income (Loss)	$	7,587		$	7,511	$	37,403	$	8,172	$	(6,606	)	$	(837	)
Add:
Interest expense, net		4,177			—		3,054		—		—			247
Income tax expense		139			73		695		124		7			8
Depreciation and amortization expense		8,290			1,605		11,915		3,874		343			882
Amortization of favorable and unfavorable contracts		(134	)		70		308		215		(19	)		—
Less:
Interest income		4			5		12		32		18			—

EBITDA	$	20,055		$	9,254	$	53,363	$	12,353	$	(6,293	)	$	300

Add:
Non-cash compensation expense		460			1,214		3,440		—		—			—
Change in deferred revenue related to MVCs	$	3,184		$	—	$	—	$	—	$	—		$	—

Adjusted EBITDA(1)	$	23,699		$	10,468	$	56,803	$	12,353	$	(6,293	)	$	300



	Summit Midstream Predecessor											Initial Predecessor
	Three Months Ended March 31,				Year-Ended December 31,							Initial Predecessor
	Three Months Ended March 31,				Year-Ended December 31,				Period from September 3, 2009 to December 31, 2009			Period from January 1, 2009 to September 3, 2009
	2012		2011		2011		2010		Period from September 3, 2009 to December 31, 2009			Period from January 1, 2009 to September 3, 2009
	(in thousands, except for volume and price amounts)
Reconciliation of EBITDA and Adjusted EBITDA to Net Cash Flows Provided by Operating Activities
Net Cash Flows Provided by (Used In) Operating Activities	$	16,605	$	8,855	$	39,942	$	9,553	$	(6,232	)	$	595
Add:
Interest expense(2)		462		—		469		—		—			247
Income tax expense		139		73		695		124		7			8
Changes in operating assets and liabilities		6,497		1,545		15,709		2,708		(50	)		(550	)
Less:
Non-cash compensation expense	$	460	$	1,214	$	3,440	$	—	$	—		$	—
Change in deferred revenue related to MVCs		3,184		—		—		—		—			—
Interest income		4		5		12		32		18			—

EBITDA(1)	$	20,055	$	9,254	$	53,363	$	12,353	$	(6,293	)	$	300

Add:
Non-cash compensation expense	$	460	$	1,214	$	3,440	$	—	$	—		$	—
Change in deferred revenue related to MVCs	$	3,184	$	—	$	—	$	—	$	—		$	—

Adjusted EBITDA(1)	$	23,699	$	10,468	$	56,803	$	12,353	$	(6,293	)	$	300

(1): EBITDA and Adjusted EBITDA for the three months ended March 31, 2012 and for the year ended December 31, 2011 include $0.2 million and $3.2 million, respectively, in transaction costs related to our acquisition of Grand River. EBITDA and Adjusted EBITDA for the year ended December 31, 2010 include $1.8 million in settlement expenses related to a dispute with a contractor at the DFW Midstream system. EBITDA and Adjusted EBITDA for the 2009 Summit Midstream Predecessor Period include transaction costs of $3.9 million primarily related to the acquisition of the DFW Midstream system in September 2009. These unusual and non-recurring expenses were included in the calculations of EBITDA and Adjusted EBITDA, and were settled in cash.
(2): Interest expense presented excludes $0.6 million and $0.2 million in amortization of deferred loan costs and $2.0 million and $3.5 million in pay in kind interest on promissory notes payable to our sponsors for the year ended December 31, 2011 and for the three months ended March 31, 2012.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

You should read the following discussion of the financial condition and results of operations of Summit Midstream Partners, LP and its subsidiaries in conjunction with the historical consolidated financial statements and related notes of Summit Midstream Partners, LLC, which we refer to as Summit Midstream Predecessor, included elsewhere in this prospectus. We sometimes refer to DFW Midstream Services LLC, or our Initial Predecessor, and Summit Midstream Predecessor collectively as our Predecessor. Among other things, those financial statements and the related notes include more detailed information regarding the basis of presentation for the following information.

Overview

Substantially all of our gas gathering agreements are underpinned by areas of mutual interest, or AMIs, and minimum volume commitments. Our AMIs cover approximately 330,000 acres in the aggregate, have original terms that range from 10 years to 25 years, and provide that any natural gas producing wells drilled by our customers within the AMIs will be shipped on our gathering systems. The minimum volume commitments, which totaled 2.6 Tcf at March 31, 2012 and, through 2020, average approximately 643 MMcf/d, are designed to ensure that we will generate a certain amount of revenue from each customer over the life of the respective gas gathering agreement, whether by collecting gathering fees on actual throughput or from cash payments to cover any minimum volume commitment shortfall. Our minimum volume commitments have original terms that range from 7 years to 15 years and, as of March 31, 2012, had a weighted average remaining life of 11.6 years assuming minimum throughput volumes for the remainder of the term. The fee-based nature of these agreements enhances the stability of our cash flows by limiting our direct commodity price exposure.

Our Operations

Our results are driven primarily by the volumes of natural gas that we gather across our systems. For the year ended December 31, 2011 and the quarter ended March 31, 2012, approximately 80% and 86%, respectively, of our revenue was associated with fee-based gathering services that we provided to our customers. Approximately 12% of our revenue was associated with (i) the sale of physical natural gas that we retained from our DFW Midstream customers to offset our power expense associated with the operation of our electric-drive compression and (ii) the sale of condensate volumes that we collected on our Grand River system. We generated the remainder of our revenue by charging certain customers with respect to costs we incurred on their behalf to deliver pipeline quality natural gas to

third-party pipelines and costs we incurred to operate electric-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 system and our gathering system in the Barnett Shale, which we refer to as the DFW Midstream system. These receipt points are connected to our gathering pipelines through which we compress natural gas and deliver it to third-party processing plants or downstream pipelines for ultimate delivery to end users.

We currently provide substantially all of our gathering services under long-term, fee-based gas gathering agreements, which limit our direct commodity price exposure, and we do not take title to the natural gas we gather on behalf of our customers. Under these agreements, we are paid a fixed fee based on the volume and thermal content of the natural gas we gather. We are party to seven, long-term gas gathering agreements with producers in the Barnett Shale and, in connection with our acquisition of the Grand River system from a subsidiary of Encana in October 2011, we entered into three, long-term gas gathering agreements with Encana and assumed 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 price risk, with the exception of the natural gas that we retain in-kind to offset the power costs we incur to operate our electric-drive compression assets on the DFW Midstream system. On the Grand River system, we either (i) consume physical gas on the system to operate our gas-fired compression assets or (ii) charge our customers for the power costs we incur to operate our electric-drive compression assets.

We also have indirect exposure to changes in commodity prices in that persistent low commodity prices may cause our customers to delay drilling or temporarily shut in production, which would reduce the volumes of natural gas that we gather. If our customers delay drilling or temporarily shut-in production due to persistently low commodity prices, our minimum volume commitments assure us that we will receive a certain amount of revenue from our customers. Please read below and "Risk Factors—Significant prolonged changes in natural gas prices could affect supply and demand, reducing throughput on our systems and adversely affecting our revenues and cash available to make distributions to you over the long-term" for additional information regarding the recent decline in natural gas prices and the impact it has had on our customers and our operations.

We have exposure to both liquids-rich and "dry" gas regions, and we believe our gathering systems are well positioned to capture additional volumes from increased producer activity in the future. Dry gas regions contain natural gas reserves that are primarily comprised of methane, as compared to liquids-rich regions that contain NGLs in addition to methane.

number of wells in various stages of completion in our AMIs that have already been connected to pad sites on the DFW Midstream system. These wells represent an opportunity to increase throughput on the DFW Midstream system at minimal incremental capital costs. In addition, because of the urban environment in which the DFW Midstream system is located, we expect that this area will continue to be developed by our customers using a high density pad site drilling strategy that is designed to support multiple wells from a single location. Instead of constructing pipelines to multiple wells, we connect to an individual pad site, some of which can accommodate up to 30 wells, and gather all of the natural gas produced at that site, thus minimizing our future capital expenditures. This pad site strategy substantially increases the efficiency of both the producers' drilling activities as well as our gathering activities and economics.

How We Evaluate Our Operations

Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on at least a monthly basis for consistency and trend analysis. These metrics include (i) throughput volume, (ii) operations and maintenance expenses, (iii) Adjusted EBITDA and (iv) distributable cash flow. We manage our business and analyze our results of operations as a single business segment.

Throughput Volume

The volume of natural gas that we gather depends on the level of production from natural gas wells connected to the Grand River and DFW Midstream systems. Aggregate production volumes are impacted by the overall amount of drilling and completion activity, as production must be maintained or increased by new drilling or other activity, because the production rate of a natural gas well declines over time. Producers' willingness to engage in new drilling is determined by a number of factors, the most important of which are the prevailing and projected prices of natural gas and NGLs, the cost to drill and operate a well, the availability and cost of capital and environmental and government regulations. We generally expect the level of drilling to positively correlate with long-term trends in commodity prices. Similarly, production levels nationally and regionally generally tend to positively correlate with drilling activity.

We must continually obtain new supplies of natural gas to maintain or increase the throughput volume on our systems. Our ability to maintain or increase existing throughput volumes and obtain new supplies of natural gas is impacted by:

•: successful drilling activity within our AMIs;
•: 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 AMIs awaiting lateral connections;
•: our ability to compete for volumes from successful new wells in the areas in which we operate outside of our existing AMIs; and
•: our ability to gather natural gas that has been released from commitments with our competitors.

We actively monitor producer activity in the areas served by our gathering systems to pursue new supply opportunities.

Operations and Maintenance Expenses

We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating and maintaining our assets. Direct labor costs,

compression costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operations and maintenance expense. Other than utilities expense, these expenses are relatively stable and largely independent of volumes delivered through our gathering systems, but may fluctuate depending on the activities performed during a specific period. Our compressors in the Barnett Shale are electric driven and power costs are directly correlated to the run-time of compressors, which depends directly on the volume of natural gas gathered. As part of our contracts with our Barnett Shale customers, we physically retain a percentage of throughput volumes that we subsequently sell to offset the power costs we incur. In addition, we pass along the fees associated with costs we incur on behalf of certain Barnett Shale customers to deliver pipeline quality natural gas to third-party pipelines. In the Piceance Basin, we either (i) consume physical gas on the system to operate our gas-fired compressors or (ii) charge our customers for the power costs we incur to operate our electric-drive compression assets.

EBITDA, Adjusted EBITDA and Distributable Cash Flow

We define EBITDA as net income, plus interest expense, income tax expense, and depreciation and amortization expense, less interest income and income tax benefit. We define Adjusted EBITDA as EBITDA plus non-cash equity compensation and deferred revenue related to MVCs. Please read "Selected Historical Financial and Operating Data—Non-GAAP Financial Measure." Although we have not quantified distributable cash flow on a historical basis, after the closing of this offering we intend to use distributable cash flow, which we define as Adjusted EBITDA plus interest income, less cash paid for interest expense and maintenance capital expenditures, to analyze our performance and liquidity. Distributable cash flow will not reflect changes in working capital balances.

EBITDA, Adjusted EBITDA and distributable cash flow are used as supplemental measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

(EBITDA and Adjusted EBITDA)

•: the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
•: the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unitholders and general partner;
•: our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and
•: the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

(Distributable Cash Flow)

•: 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.

Note Regarding Non-GAAP Financial Measures

EBITDA, Adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial condition and results of operations.

Net income and net cash flows provided by operating activities are the GAAP measures most directly comparable to EBITDA, Adjusted EBITDA and distributable cash flow. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as an analytical tool because it excludes some but not all items that affect the most directly comparable GAAP financial measure. You should not consider EBITDA, Adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because EBITDA, Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. Please read "Selected Historical Financial and Operating Data—Non-GAAP Financial Measure."

General Trends and Outlook

Our business has been, and we expect our future business to continue to be, affected by the key trends discussed below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Natural gas supply and demand dynamics

Natural gas continues to be a critical component of energy supply and demand in the United States. Recently, the price of natural gas has been at historically low levels, with the prompt month NYMEX natural gas futures price reaching $2.42 per MMBtu as of May 31, 2012, compared to a high of $13.58 per MMBtu in July 2008. The lower price of natural gas is due in part to increased production, especially from unconventional sources, such as natural gas shale plays, high levels of natural gas in storage, warm winter weather and the effects of the economic downturn starting in 2008. According to the U.S. Energy Information Administration ("EIA"), average annual natural gas production in the United States increased 14.1% from 55.3 Bcf/d to 63.0 Bcf/d from 2008 to 2011. Over the same time period, natural gas consumption increased only 4.7% to 66.8 Bcf/d. Furthermore, the amount of natural gas in storage in the continental United States has increased from approximately 2.2 Tcf as of June 3, 2011 to approximately 2.9 Tcf as of June 1, 2012 due to the unseasonably warm winter of 2011-2012 and to the decisions of many producers to store natural gas in the expectation of higher prices in the future. In response to lower natural gas prices, the number of natural gas drilling rigs has declined from approximately 1,403 as of December 31, 2008 to approximately 515 as of May 31, 2012 according to Smith Bits, as a number of producers have curtailed their exploration and production activities. We believe that over the short term, until the supply overhang has been reduced and the economy sees more robust growth, natural gas pricing is likely to be constrained.

Over the long term, we believe that the prospects for continued natural gas demand are favorable and will be driven by population and economic growth, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation due to the low prices of natural gas and stricter government environmental regulations on the mining and burning of coal. For example, according to the EIA, in December 2008, 50% of the electricity in the United States was generated by coal-fired power plants and in December 2011, 41% of the electricity in the United States was generated by coal-fired power plants. In January 2012, the EIA projected total annual domestic consumption of natural gas to increase from approximately 22.9 Tcf in 2009 to approximately 26.5 Tcf in 2035. Consistent with the rise in consumption, the EIA projects that total domestic natural gas production will continue to grow through 2035 to 27.8 Tcf. We believe that increasing consumption of natural gas will continue to drive natural gas drilling and production over the long-term throughout the United States.

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Growth in production from U.S. shale plays

Over the past several years, a fundamental shift in production has emerged with the growth of natural gas production from unconventional resources (defined by the EIA as natural gas produced from shale formations and coalbeds). While the EIA expects total domestic natural gas production to grow from 20.6 Tcf in 2009 to 27.8 Tcf in 2035, it expects shale gas production to 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 natural gas plays and advances in technology that have allowed producers to extract significant volumes of natural gas from these plays at cost-advantaged per unit economics 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 other unconventional resource plays. To help fund their drilling program in many of these areas, including in the Piceance Basin and the Barnett Shale, a number of producers have also entered into joint venture arrangements with large international operators and private equity sponsors. These producers and their joint venture partners have committed significant capital to the development of the Piceance 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 operations in certain dry gas regions where the economics of natural gas production are less favorable. Drilling activities focused in liquids-rich regions have continued and, in some cases, have increased, as the high Btu content associated with liquids-rich production enhances overall drilling economics, even in a low natural gas price environment.

Interest rate environment

The credit markets recently have experienced near-record lows in interest rates. As the overall economy strengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. This could affect our ability to access the debt capital markets to the extent we may need to in the future to fund our growth. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Although this could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.

Rising operating costs and inflation

The current high level of natural gas exploration, development and production activities across the United States has resulted in increased competition for personnel and equipment. This is causing increases in the prices we pay for labor, supplies and property, plant and equipment. An increase in the general level of prices in the economy could have a similar effect. We attempt to recover increased costs from our customers, but there may be a delay in doing so or we may be unable to recover all of these costs. To the extent we are unable to procure necessary supplies or recover higher costs, our operating results will be negatively impacted.

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Results of Operations—Combined Overview

The following table and discussion presents certain historical consolidated financial data of our Predecessor for the periods indicated.



	Summit Midstream Predecessor
	Summit Midstream Predecessor															Initial Predecessor
	Three Months Ended March 31,															Initial Predecessor
	Three Months Ended March 31,						Year Ended December 31,						Period from September 3, 2009 to December 31, 2009			Period from January 1, 2009 to September 3, 2009
	2012			2011			2011			2010			Period from September 3, 2009 to December 31, 2009			Period from January 1, 2009 to September 3, 2009
	(in thousands, except for volume and price amounts)
Statement of Operations Data:
Revenue:
Gathering services and other fees	$	31,918		$	17,128		$	91,421		$	29,358		$	1,714		$	1,910
Natural gas and condensate sales		3,731			2,117			12,439			2,533			—			—
Amortization of favorable and unfavorable contracts(1)		134			(70	)		(308	)		(215	)		19			—

Total revenue	$	35,783		$	19,175		$	103,552		$	31,676		$	1,733		$	1,910
Costs and expenses:
Operations and maintenance		10,989			6,148			29,855			9,503			1,147			1,010
General and administrative		4,412			3,843			17,476			10,035			2,939			600
Transaction costs		193			—			3,166			—			3,921			—
Depreciation and amortization		8,290			1,605			11,915			3,874			343			882

Total costs and expenses		23,884			11,596			62,412			23,412			8,350			2,492

Interest (expense) income, net		(4,173	)		5			(3,042	)		32			18			(247	)
Income tax expense		(139	)		(73	)		(695	)		(124	)		(7	)		(8	)

Net income (loss)	$	7,587		$	7,511		$	37,403		$	8,172		$	(6,606	)	$	(837	)

Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	16,605		$	8,855		$	39,942		$	9,553		$	(6,232	)	$	595
Investing activities		(20,577	)		(19,606	)		(667,710	)		(153,719	)		(64,415	)		(40,777	)
Financing activities		(579	)		8,000			633,809			114,132			110,102			40,182
Balance Sheet Data (at period end):
Cash and cash equivalents	$	10,911					$	15,462		$	9,421		$	39,455
Trade accounts receivable		30,997						27,476			10,238			1,373
Property, plant, and equipment, net		652,732						642,552			277,765			140,704
Total assets		1,032,164						1,026,498			340,095			215,982
Total debt(2)		353,940	(2)					349,893	(2)		—			—
Other Financial Data:
EBITDA(3)	$	20,055		$	9,254		$	53,363		$	12,353		$	(6,293	)	$	300
Adjusted EBITDA(3)	$	23,699		$	10,468		$	56,803		$	12,353		$	(6,293	)	$	300
Capital expenditures		20,577			19,606			78,248			153,719			19,519			40,777
Acquisition expenditures(4)		—			—			589,462			—			44,896			—
Operating data:
Average throughput (MMcf/d)		908.4			285.2			428.0			134.3			15.4			15.7

(1): The amortization of favorable and unfavorable contracts relates to gas gathering agreements that were deemed to be above or below market on September 3, 2009, the date of the acquisition of the DFW Midstream system, which are amortized on a units-of-production basis over the life of the applicable contract.

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The life of the contract is the period over which the contract is expected to contribute directly or indirectly to our future cash flows.

(2): Includes $202.9 million and $206.9 million of debt outstanding under our promissory notes payable to our sponsors at December 31, 2011 and March 31, 2012. On July 2, 2012, the outstanding balance under the notes was paid in full.
(3): EBITDA and Adjusted EBITDA for the three months ended March 31, 2012 and for the year ended December 31, 2011 include $0.2 million and $3.2 million, respectively, in transaction costs related to our acquisition of Grand River. EBITDA and Adjusted EBITDA for the year ended December 31, 2010 include $1.8 million in settlement expenses related to a dispute with a contractor at the DFW Midstream system. EBITDA and Adjusted EBITDA for the 2009 Summit Midstream Predecessor Period include transaction costs of $3.9 million primarily related to the acquisition of the DFW Midstream system in September 2009. These unusual and non-recurring expenses were included in the calculations of EBITDA and Adjusted EBITDA and were settled in cash.
(4): Reflects the acquisition of certain assets of the DFW Midstream system from Chesapeake in September 2009 and the acquisition of the Grand River System in October 2011.

Items Affecting the Comparability of Our Financial Results

The historical results of operations of our Predecessor may not be comparable to our future results of operations for the reasons described below:

•

Because we acquired our initial interest in the DFW Midstream system from Texas Competitive Electric Holdings Company, LLC ("TCEH"), an indirect subsidiary of Energy Future Holdings Corp., effective as of September 3, 2009, the financial and operational data for 2009 that is presented and discussed in this prospectus is generally bifurcated between the period that our Initial Predecessor owned those assets and the period from the acquisition of those assets by Summit Midstream Predecessor through December 31, 2009.

•

The historical consolidated financial statements and related notes of our Initial Predecessor:

•: have been carved out of the accounting records maintained by Energy Future Holdings and its subsidiaries. Certain accounts such as trade accounts receivables, accounts payable, pre-paid expenses and certain accrued liabilities relating to the activities of our Initial Predecessor were recorded on the books of other Energy Future Holdings entities and estimates of those accounts have been included in the consolidated financial statements;
•: include an estimate for general and administrative ("G&A") expenses, as Energy Future Holdings did not allocate any of the central finance and administrative costs to this operating entity;
•: reflect the operation of the DFW Midstream system with different business strategies and as part of a larger business rather than the stand-alone fashion in which we operate it. Please read "Business—Business Strategies;" and
•: do not include any results from certain natural gas gathering assets that we acquired from Chesapeake Energy Corporation on September 3, 2009 that are included in the DFW Midstream system.

•

The historical consolidated financial statements and related notes of Summit Midstream Predecessor:

•: reflect a 75% ownership interest in the entity we acquired from TCEH from September 4, 2009 to June 18, 2010, the date on which Summit Midstream Predecessor purchased the remaining 25% membership interest from TCEH for $90.7 million;

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•: include transaction expenses of $3.9 million in 2009 that we incurred in connection with our formation and our initial acquisition of assets. These expenses 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;
•: include charges associated with a transition services agreement that we entered into with Energy Future Holdings effective September 3, 2009. Under the terms of the transition services agreement, we paid Energy Future Holdings $38,700, $0.1 million and $0.1 million for the years ended December 31, 2011 and 2010 and the period from September 3, 2009 through December 31, 2009, respectively; and
•: do not include any results from the acquisition of the Grand River system prior to November 2011.

•: We anticipate incurring approximately $2.5 million of G&A expense attributable to operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer liability insurance costs, and director compensation. These incremental G&A expenses are not reflected in the historical consolidated financial statements of our Initial Predecessor or Summit Midstream Predecessor.
•: Following the closing of this offering, we intend to make cash distributions to our unitholders equal to our minimum quarterly distribution of $ per unit per quarter ($ per unit on an annualized basis). Based on the terms of our partnership agreement, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations, borrowings under our amended and restated revolving credit facility and future issuances of equity and debt securities. Historically, Summit Midstream Predecessor largely relied on internally generated cash flows and capital contributions from Energy Capital Partners and GE Energy Financial Services to satisfy its capital expenditure requirements.

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011

Volume. Our revenues are primarily attributable to the volume of natural gas that we gather and the rates we charge to gather that natural gas. Throughput volumes increased 623.2 MMcf/d, or 219%, from 285.2 MMcf/d for the three months ended March 31, 2011 to 908.4 MMcf/d for the three months ended March 31, 2012. This increase is due to the continued development of the DFW Midstream system and the acquisition of the Grand River system. There were 307 wells and 61 drilling pad sites and 187 wells and 40 drilling pad sites connected to the DFW Midstream system as of March 31, 2012 and 2011, respectively. The DFW Midstream system included 110 miles and 86 miles of pipeline as of March 31, 2012 and 2011, respectively. Throughput volumes for the DFW Midstream system averaged 314.8 MMcf/d for the three months ended March 31, 2012. We acquired the Grand River system in October 2011. Throughput volumes for the Grand River system averaged 593.6 MMcf/d for the three months ended March 31, 2012.

Revenue. Total revenue increased $16.6 million, or 87%, from $19.2 million for the three months ended March 31, 2011 to $35.8 million for the three months ended March 31, 2012. Gathering services and other fees increased $14.8 million, or 86%, from $17.1 million for the three months ended March 31, 2011 to $31.9 million for the three months ended March 31, 2012. This increase was primarily the result of increased throughput volumes on the DFW Midstream system, offset by a

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decrease of $0.15 per Mcf, or 17%, in the average throughput rates from $0.52 per Mcf for the three months ended March 31, 2011 to $0.37 per Mcf for the three months ended March 31, 2012. This decrease is primarily due to the fact that the Grand River system generates a lower average gathering fee per Mcf than our DFW Midstream system. Gas gathering revenue for the Grand River system was $15.7 million for the three months ended March 31, 2012. Natural gas and condensate sales increased $1.6 million, or 76%, from $2.1 million for the three months ended March 31, 2011 to $3.7 million for the three months ended March 31, 2012. The increase in revenue attributable to natural gas and condensate sales is primarily the result of increased sales of natural gas that we retain from our DFW Midstream customers to offset the costs we incur to operate our electric-drive compression assets in the Barnett Shale. Revenue associated with condensate sales for the Grand River system was $1.3 million for the three months ended March 31, 2012.

Operations and maintenance expense. Operations and maintenance expense increased $4.8 million, or 79%, from $6.1 million for the three months ended March 31, 2011 to $11.0 million for the three months ended March 31, 2012. This increase was primarily the result of operations and maintenance expense for the Grand River system of $5.8 million for the three months ended March 31, 2012. Ad valorem taxes increased approximately $0.4 million on the DFW Midstream system for the three months ended March 31, 2012 compared to the three months ended March 31, 2011. The increase in operations and maintenance expense was offset by a $0.6 million reduction in CO₂ related expenses for the three months ended March 31, 2012 compared to the comparable period in 2011. Compressor related expenses decreased $0.3 million for the three months ended March 31, 2012 compared to the three months ended March 31, 2011 due to cancellation of a third-party compressor operating agreement in the fourth quarter of 2011.

General and administrative ("G&A") expense. G&A expense increased $0.6 million, or 15%, from $3.8 million for the three months ended March 31, 2011 to $4.4 million for the three months ended March 31, 2012. Salary and benefit expenses increased $0.9 million, or 70%, from $1.3 million for the three months ended March 31, 2011 to $2.3 million for the three months ended March 31, 2012 due to increased headcount to support our growth. Insurance related costs increased $0.3 million and employee related costs increased $0.3 million for the three months ended March 31, 2012 compared to the three months ended March 31, 2011 as a result of the acquisition of the Grand River system in October 2011. The increase in G&A expenses was partially offset by a decrease in non-cash unit based compensation for the three months ended March 31, 2012 compared to the three months ended March 31, 2011. Non-cash unit based compensation expense relative to net profits interests held by certain current and former members of management decreased $0.8 million, or 62%, from $1.2 million for the three months ended March 31, 2011 to $0.5 million for the three months ended March 31, 2012.

Depreciation and amortization expense. Depreciation and amortization expense increased $6.7 million, or 417%, from $1.6 million for the three months ended March 31, 2011 to $8.3 million for the three months ended March 31, 2012. This increase was primarily the result of the depreciation associated with additional assets placed into service in connection with the development of the DFW Midstream system during 2011. Depreciation and amortization expense for the Grand River system was $5.4 million for the three months ended March 31, 2012.

Interest expense and affiliated interest expense. Interest expense increased $4.2 million for the three months ended March 31, 2012 compared to the three months ended March 31, 2011. This increase was primarily the result of entering into our revolving credit facility in May 2011 and issuing $200 million of promissory notes to our sponsors in connection with the acquisition of the Grand River system. We did not have a revolving credit facility or outstanding promissory notes during the three months ended March 31, 2011.

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Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Volume. Our revenues are primarily attributable to the volume of natural gas that we gather and the rates we charge to gather that natural gas. Throughput volumes increased 293.7 MMcf/d, or 219%, from 134.3 MMcf/d for the year ended December 31, 2010 to 428.0 MMcf/d for the year ended December 31, 2011. This increase was due to the continued development of the DFW Midstream system. There were 275 wells and 58 drilling pad sites and 160 wells and 33 drilling pad sites connected to the DFW Midstream system as of December 31, 2011 and 2010, 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 329.0 MMcf/d for the year ended December 31, 2011. We acquired the Grand River system in October 2011. Throughput volumes for the Grand River system averaged 605.9 MMcf/d for the two months that are 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 for the year ended December 31, 2011. Gathering services and other fees increased $62.1 million, or 211%, from $29.4 million for the year ended December 31, 2010 to $91.4 million for the year ended December 31, 2011. This increase was primarily the result of increased throughput volumes on the DFW Midstream system, offset by a decrease of $0.04 per Mcf, or 7%, in the average throughput rates from $0.57 per Mcf for the year ended December 31, 2010 to $0.53 per Mcf for the year ended December 31, 2011. This decrease is primarily due to the fact that the Grand River system generates a lower average gathering fee per Mcf than our DFW Midstream system. Gas gathering revenue for the Grand River system was $11.0 million for the two months that are included in our financial results for the year ended December 31, 2011. Natural gas and condensate sales increased $9.9 million, or 391%, from $2.5 million for the year ended December 31, 2010 to $12.4 million for the year ended December 31, 2011. The increase in revenue attributable to natural gas and condensate sales is primarily the result of increased sales of natural gas that we retain from our DFW Midstream customers to offset the costs we incur to operate our electric-drive compression assets in the Barnett Shale. Revenue associated with condensate sales for the Grand River 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 for the year ended December 31, 2010 to $29.9 million for the year ended December 31, 2011. This increase was primarily the result of increased throughput volumes on the DFW Midstream system. Utility expense for our electric drive compressors increased $9.1 million, or 206%, from $4.4 million for the year ended December 31, 2010 to $13.5 million for the year ended December 31, 2011 due to increased volumes and the associated increased power cost to operate the compression. Operations and maintenance expenses for the Grand River system were $3.9 million for the two months that are included in our financial results for the year ended December 31, 2011.

General and administrative expense. G&A expense increased $7.4 million, or 74%, from $10.0 million for the year ended December 31, 2010 to $17.5 million for the year ended December 31, 2011. We recorded non-cash compensation expense of $3.4 million for the year ended December 31, 2011 relative to profits interests held by certain members of management. We did not record non-cash compensation expense for the year ended December 31, 2010. Salary and benefit expenses increased $2.0 million, or 45%, from $4.3 million for the year ended December 31, 2010 to $6.3 million for the year ended December 31, 2011 due to increased headcount to support our growth. We did not have these expenses for the year ended December 31, 2010. Due diligence costs relative to potential asset acquisitions were $1.3 million in 2011 compared to insignificant due diligence costs in 2010. The increase in G&A expenses was offset by decreases in legal expenses for the year ended December 31, 2011 compared to the year ended December 31, 2010. Legal expenses decreased $2.0 million in 2011 primarily as the result of decreased legal activities relative to relationships with contractors and

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sub-contractors associated with the DFW Midstream system. We had $1.8 million in settlement expenses in 2010 related 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 primarily related 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 $8.1 million, or 208%, from $3.9 million for the year ended December 31, 2010 to $12.0 million for the year ended December 31, 2011. This increase was primarily the result of the depreciation 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 $3.8 million for the two months that are included 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. This increase 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 issuing $200 million of promissory notes to our sponsors in connection with 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.

Year Ended December 31, 2010 Compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period

Volume. Throughput volumes increased 118.6 MMcf/d, or 755%, from 15.7 MMcf/d for the 2009 Initial Predecessor Period to 134.3 MMcf/d for the year ended December 31, 2010. Throughput volumes increased 118.9 MMcf/d, or 772%, from 15.4 MMcf/d for the 2009 Summit Midstream Predecessor Period to 134.3 MMcf/d for the year ended December 31, 2010. Throughput volumes increased significantly for the year ended December 31, 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period due to the continued development of the DFW Midstream system. There were 160 wells and 33 drilling pad sites and 20 wells and 4 drilling pad sites connected to the DFW Midstream system as of December 31, 2010 and December 31, 2009, respectively. The DFW Midstream system included 83 miles and 12 miles of pipeline as of December 31, 2010 and December 31, 2009, respectively.

Revenue. Revenue increased $28.0 million, or 770%, from $1.9 million for the 2009 Initial Predecessor Period and $1.7 million for the 2009 Summit Midstream Predecessor Period to $31.7 million for the year ended December 31, 2010. Gas gathering revenue increased $25.8 million, or 710%, from $1.9 million for the 2009 Initial Predecessor Period and $1.7 million for the 2009 Summit Midstream Predecessor Period to $29.4 million for the year ended December 31, 2010. This increase was primarily the result of increased throughput volumes on the DFW Midstream system. Average throughput rates decreased $0.01 per Mcf, or 2%, from $0.58 per Mcf for the 2009 Summit Midstream Predecessor Period to $0.57 per Mcf for the year ended December 31, 2010. Natural gas and condensate sales were $2.5 million for the year ended December 31, 2010. Revenue for the year ended December 31, 2010 included sales of natural gas that we retain from DFW Midstream customers to offset the costs we incur to operate our electric-drive compression assets in the Barnett Shale.

Operations and maintenance expense. Operations and maintenance expense increased $7.3 million, or 341%, from $1.0 million for the 2009 Initial Predecessor Period and $1.1 million for the 2009 Summit Midstream Predecessor Period to $9.5 million for the year ended December 31, 2010. This increase was primarily the result of increased throughput volumes on the DFW Midstream system. Utility expense for our electric drive compressors were $4.4 million for the year ended December 31, 2010. Utility expense for the 2009 Initial Predecessor Period and for the 2009 Summit Midstream

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Predecessor Period was insignificant. The remaining increase in operations and maintenance expense for the year ended December 31, 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period was primarily the result of additional throughput on the DFW Midstream system and additional compression being placed into service.

General and administrative expense. G&A expense increased $6.5 million, or 184%, from $0.6 million for the 2009 Initial Predecessor Period and $2.9 million for the 2009 Summit Midstream Predecessor Period to $10.0 million for the year ended December 31, 2010. Legal expenses increased $2.0 million for the year ended December 31, 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period primarily as the result of legal activities relative to relationships with contractors and sub-contractors associated with the DFW Midstream system. The remaining increase in G&A expenses for the year ended December 31, 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period is the result of our ownership of the DFW Midstream system for the full year 2010. We acquired our initial assets of our DFW Midstream system effective as of September 3, 2009. Additionally, we increased our headcount in 2010 compared to 2009 as we continued construction and development of the DFW Midstream system.

Transaction costs. Transaction costs were $3.9 million for the 2009 Summit Midstream Predecessor Period. These transaction costs were primarily related to the acquisition of the DFW Midstream system in September 2009. We did not have transaction costs for the 2009 Initial Predecessor Period or the year ended December 31, 2010.

Depreciation and amortization expense. Depreciation and amortization expense increased $2.6 million, or 216%, from $0.9 million for the 2009 Initial Predecessor Period and $0.3 million for the 2009 Summit Midstream Predecessor Period to $3.9 million for the year ended December 31, 2010. This increase was primarily the result of the depreciation associated with assets placed into service in connection with the expansion and development of the DFW Midstream system in 2010.

Interest expense. Interest expense decreased $0.2 million for the year ended December 31, 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period. Interest expense for the 2009 Initial Predecessor Period included $0.2 million related to an intercompany capital allocation charge during the ownership of the DFW Midstream system by our Initial Predecessor. We did not have an intercompany capital allocation charge for the year ended December 31, 2010.

Liquidity and Capital Resources

Since the acquisition of our initial assets in September 2009, our sources of liquidity have included cash generated from operations, equity investments by our sponsors, Energy Capital Partners and GE Energy Financial Services, and borrowings under our revolving credit facility.

Following the closing of this offering we expect our sources of liquidity to include:

•: cash generated from operations;
•: borrowings under our amended and restated revolving credit facility; and
•: issuances of debt and equity securities.

We believe that the cash generated from these sources will be sufficient to allow us to distribute the minimum quarterly distribution to all of our unitholders and the corresponding distribution on our 2.0% general partner interest and to meet our requirements for working capital and capital expenditures for the foreseeable future.

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Cash Flows

The following table reflects cash flows for the applicable periods:



	Summit Midstream Predecessor
	Summit Midstream Predecessor															Initial Predecessor
	Three Months Ended March 31,															Initial Predecessor
	Three Months Ended March 31,						Year Ended December 31,						Period from September 3, 2009 to December 31, 2009			Period from January 1, 2009 to September 3, 2009
	2012			2011			2011			2010			Period from September 3, 2009 to December 31, 2009			Period from January 1, 2009 to September 3, 2009
	(in thousands)
Operating activities	$	16,605		$	8,855		$	39,942		$	9,553		$	(6,232	)	$	595
Investing activities		(20,577	)		(19,606	)		(667,710	)		(153,719	)		(64,415	)		(40,777	)
Financing activities		(579	)		8,000			633,809			114,132			110,102			40,182

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011

Operating activities. Cash flows from operating activities increased by $7.7 million, or 87%, from $8.9 million for the three months ended March 31, 2011 to $16.6 million for the three months ended March 31, 2012. The increase in cash flows from operating activities is a direct result of the increase in volumes on the DFW Midstream system for the three months ended March 31, 2012 compared to three months ended March 31, 2011 and the inclusion of operations on the Grand River system for the three months ended March 31, 2012.

Investing activities. Cash flows used for investing activities increased by $1.0 million, or 5.1%, from $19.6 million for the three months ended March 31, 2011 to $20.6 million for the three months ended March 31, 2012. Capital expenditures on the DFW Midstream system decreased $5.0 million, or 25%, from $19.6 million for the three months ended March 31, 2011 to $14.6 million for the three months ended March 31, 2012. Capital expenditures on the Grand River system were $5.6 million for the three months ended March 31, 2012.

Financing activities. Cash flows from financing activities were $8.0 million for the three months ended March 31, 2011 and consisted of capital contributions from Energy Capital Partners to support capital needs related to the construction of the DFW Midstream system. No capital contributions were made during the three months ended March 31, 2012. Cash flows from financing activities of $0.6 million for the three months ended March 31, 2012 consisted of deferred loan costs and initial public offering costs.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Operating activities. Cash flows from operating activities increased by $30.4 million, or 318%, from $9.6 million for the year ended December 31, 2010 to $40.0 million for the year ended December 31, 2011. The increase in cash flows from operating activities is a direct result of the significant increase in volumes on the DFW Midstream system during 2011 compared to 2010 and the inclusion of two months of operations on the Grand River system for the year ended December 31, 2011.

Investing activities. Cash flows used for investing activities increased by $514.0 million, or 334%, from $153.7 million for the year ended December 31, 2010 to $667.7 million for the year ended December 31, 2011. The increase in cash flows used for investing activities is primarily due to the acquisition of the Grand River system for $590.0 million. Capital expenditures decreased by $79.2 million, or 49%, from $154.0 million for the year ended December 31, 2010 to $74.8 million for the year ended December 31, 2011. Capital expenditures in 2010 were higher due to the installation and commissioning of compressor stations on the DFW Midstream system.

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Financing activities. Cash flows from financing activities increased by $519.7 million, or 455%, from $114.1 million for the year ended December 31, 2010 to $633.8 million for the year ended December 31, 2011. The increase in cash flows from financing activities is primarily due to the acquisition of the Grand River system. Summit Midstream Predecessor received equity contributions of $410 million and a $200.0 million non-recourse loan from Energy Capital Partners and GE Energy Financial Services to acquire the Grand River system. Summit Midstream Predecessor closed on our revolving credit facility in May 2011. Upon closing the revolving credit facility, Summit Midstream Predecessor made a distribution to our sponsors of $132.9 million of the $142.0 million drawn at closing.

Year Ended December 31, 2010 Compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period

Operating activities. Cash flows from operating activities increased by $15.2 million from $0.6 million for the 2009 Initial Predecessor Period and $(6.2) million for the 2009 Summit Midstream Predecessor Period to $9.6 million for the year ended December 31, 2010. The increase in cash flows from operating activities is related to the increased volumes on the DFW Midstream system during 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period. The increase in volumes resulted in an increase of net income by $15.6 million, from $(0.8) million for the 2009 Initial Predecessor Period and $(6.6) million for the 2009 Summit Midstream Predecessor Period to $8.2 million for the year ended December 31, 2010.

Investing activities. Cash flows used for investing activities increased by $48.5 million, or 46%, from $40.8 million for the 2009 Initial Predecessor Period and $64.4 million for the 2009 Summit Midstream Predecessor Period to $153.7 million for the year ended December 31, 2010. The cash used for investing activities increased due to the installation and commissioning of the compressor stations on the DFW Midstream system during 2010.

Financing activities. The cash flows from financing activities during the 2009 Initial Predecessor Period, the 2009 Summit Midstream Predecessor Period and the year ended December 31, 2010 were capital contributions from Energy Capital Partners. During the 2009 Summit Midstream Predecessor Period, Energy Capital Partners contributed $107.0 million at formation and then contributed an additional $27.9 million to support capital needs related to the construction of the DFW Midstream system. In the year ended December 31, 2010, Energy Capital Partners contributed $194.1 million in support of the continued growth and construction of the DFW Midstream system. In June 2010, we purchased the remainder of Energy Future Holdings' membership interests related to the DFW Midstream system for $90.7 million, which was funded with the capital contributed by Energy Capital Partners.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Capital Requirements

The natural gas gathering segment of the midstream energy business is capital-intensive, requiring significant investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our partnership agreement will require that we categorize our capital expenditures as either:

•: maintenance capital expenditures, which 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-term operating income or operating capacity; or

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•: expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long-term.

For the year ended December 31, 2011, our total capital expenditures were $667.7 million. Approximately $590.0 million of the capital expenditures in 2011 were related to our acquisition of the Grand River system in October 2011. The remainder were primarily associated with the construction of new pipeline infrastructure to connect new pad sites on our DFW Midstream system and to connect new pad sites and central receipt points on our Grand River system. Historically, we did not make a distinction between maintenance and expansion capital expenditures. We have estimated, however, that approximately $3.1 million of these capital expenditures were maintenance capital expenditures.

We are forecasting $78.2 million in capital expenditures for the year ending December 31, 2012, of which $73.0 million represents expansion capital expenditures and $5.2 million represents maintenance capital expenditures. Our 2012 budgeted expansion capital expenditures include:

•: $16.4 million to construct pipeline laterals and tie in additional pad sites for customers on the DFW Midstream system;
•: $13.7 million related to the installation of additional compression assets and construction of several looping pipelines on the DFW Midstream system in order to increase system capacity to over 450 MMcf/d and optimize throughput hydraulics and operating pressures;
•: $11.8 million related to the construction of medium-pressure pipelines and the installation of additional compression-related assets in the Orchard field on the Grand River system;
•: $10.0 million associated with the procurement and installation of pad site meter equipment at approximately 400 existing pad sites on the Grand River system;
•: $9.4 million to expand and improve hydraulic efficiency of our assets in the Mamm Creek field on the Grand River system; and
•: $5.7 million to connect five pad sites adjacent to the DFW Midstream system for our new customer, Beacon E&P.

As of March 31, 2012, we have spent approximately $20.6 million of our 2012 expansion capital budget.

We anticipate that we will continue to make significant expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. We expect that our future expansion capital expenditures will be funded by borrowings under our amended and restated revolving credit facility and the issuance of debt and equity securities.

Distributions

We intend to pay a quarterly distribution at an initial rate of $ per unit, which equates to an aggregate distribution of $ million per quarter, or $ million on an annualized basis, based on the number of common and subordinated units anticipated to be outstanding immediately after the closing of this offering and the related distributions on our 2.0% general partner interest. We do not have a legal obligation to make distributions except as provided in our partnership agreement.

Our Amended and Restated Revolving Credit Facility

Effective May 7, 2012, we amended and restated our revolving credit facility with a syndicate of lenders to increase our borrowing capacity from $285 million to $550 million. Substantially all of our assets are pledged as collateral under our amended and restated revolving credit facility. The amended and restated revolving credit facility matures in May 2016 and, at our option, borrowings thereunder bear interest at a variable rate per annum equal to either LIBOR, plus the applicable margins ranging

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from 2.5% to 3.5%, or at a base rate, plus the applicable margins ranging from 1.5% to 2.5%. The events that constitute an event of default under our amended and restated revolving credit facility are customary for credit facilities of this size and nature.

Our amended and restated credit agreement contains affirmative and negative covenants customary for credit facilities of this size and nature, that, among other things, 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 be less 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 (or 5.50 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 to customary 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 transactions of such types;
•: pay dividends or make cash distributions, provided that we may make quarterly distributions to our unitholders, so long as no default or event of default under the amended and restated credit agreement then exists or would result therefrom, and subject to compliance (on both a pro forma basis and after giving effect to the making of such distribution) with our financial performance covenants 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 swap agreements 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 March 31, 2012, we were in compliance with the financial and other covenants in our amended and restated revolving credit facility.

In addition to the uses described in "Use of Proceeds," we expect borrowings under our amended and restated revolving credit facility to be used for (i) the refinancing and repayment of certain existing indebtedness, (ii) working capital and other general partnership purposes and (iii) capital expenditures. There was $352.0 million drawn under our amended and restated revolving credit facility at July 16, 2012.

Promissory Notes Payable to Sponsors

In connection with our acquisition of the Grand River system, Summit Investments executed promissory notes, on an unsecured basis, with our sponsors. The notes totaled $200 million and had an 8% interest rate and a maturity date of October 27, 2013. Summit Investments exercised its option to make a payment in kind for all interest due as of March 31, 2012. The amount of interest paid in kind and accrued to the balance of the notes as of March 31, 2012 was $6.9 million, resulting in $206.9 million as the amount outstanding on the notes as of March 31, 2012. During 2011 and the three months ended March 31, 2012, Summit Investments capitalized $0.9 million of the $2.9 million interest expense and $0.6 million of the $4.0 million interest expense, respectively, related to costs incurred on capital projects under construction. As of March 31, 2012, the aggregate carrying value of these notes approximated the fair value.

The promissory notes payable to our sponsors were repaid in full on July 2, 2012.

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Credit Risk and Customer Concentration

We examine the creditworthiness of third-party customers to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. A significant percentage of our revenue is attributable to three producer customers and one natural gas marketer. Chesapeake, Carrizo, TOTAL and Energy Transfer Fuels each accounted for more than 10% of our $103.6 million in consolidated revenue for the year ended December 31, 2011, accounting for 34%, 17%, 10% and 12%, respectively, of our consolidated revenue for that year. Although we have contractual arrangements with each of these counterparties of varying duration, if one or more of these customers were to default on their contractual obligations or if we were unable to renew our contract with one or more of these customers on favorable terms, we may not be able to replace any of these customers in a timely fashion, on favorable terms or at all. In any of these situations, our cash flows and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our revenue.

Contractual Obligations

The table below summarizes our contractual obligations and other commitments as of December 31, 2011:

Contractual Obligation	Total		Less Than 1 Year		1-3 Years		3-5 Years		More than 5 Years

	(in thousands)
Long-term debt and interest payments(1)	$	169,402	$	4,381	$	15,240	$	149,781	$	—
Promissory notes payable to sponsors(2)		234,614		—		234,614		—		—
Operating leases		2,118		532		996		590		—

Total	$	406,134	$	4,913	$	250,850	$	150,371	$	—

(1): On May 7, 2012, we amended and restated our revolving credit facility. On May 8, 2012, we borrowed $163.0 million under this facility and used the $160.0 million of those borrowings to repay amounts outstanding under the promissory notes payable to our sponsors. On July 2, 2012, we borrowed $50.0 million under the amended and restated revolving credit facility and used a portion of this borrowing to repay the remaining $49.2 million of the promissory notes payable to our sponsors. As of July 16, 2012, the outstanding balance under our amended and restated revolving credit facility was $352.0 million.
(2): The promissory notes payable to our sponsors were repaid in full on July 2, 2012.

Quantitative and Qualitative Disclosures about Market Risk

Interest Rate Risk

We have exposure to changes in interest rates on our indebtedness associated with our amended and restated revolving credit facility. The credit markets have recently experienced historical lows in interest rates. As the overall economy strengthens, it is possible that monetary policy will tighten further, resulting in higher interest rates to counter possible inflation. Interest rates on floating rate credit facilities and future debt offerings could be higher than current levels, causing our financing costs to increase accordingly.

Summit Midstream Predecessor entered into our revolving credit facility in May 2011, which was amended and restated on May 7, 2012. A hypothetical increase or decrease in interest rates of 1.0% would have increased or decreased, respectively, our interest expense by $1.5 million for the year ended December 31, 2011.

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Commodity Price Risk

Because we currently generate a substantial majority of our revenues pursuant to long-term, fixed-fee gas gathering agreements that include minimum volume commitments and AMIs, our only direct commodity price exposure relates to (i) our sale of physical natural gas we retain from our DFW Midstream 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 Shale customers permit us to retain a certain quantity of natural gas that is intended to offset the power costs we incur to operate our electric-drive compression assets. Our gas gathering agreements with our Grand River customers permit us to retain condensate volumes from the Grand River gathering lines. We manage our direct exposure to natural gas and power prices through the use of forward power purchase contracts with wholesale power providers that require us to purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices at the Waha Hub Index. Because we also sell our retainage gas at prices that are based on the Waha Hub Index, we have effectively fixed the relationship between our compression electricity expense and natural gas sales. We do not enter into risk management contracts for speculative purposes.

Impact of Seasonality

Our results of operations on our gathering systems are not materially affected by seasonality.

Critical Accounting Policies and Estimates

In our financial reporting process, we employ methods, estimates and assumptions that affect the reported amounts of assets and liabilities as of the balance sheet date of our financial statements. These methods, estimates and assumptions also affect the reported amounts of revenues and expenses, including fair value measurements and disclosure of contingencies, during the reporting period. Our actual results could differ from these estimates if the underlying assumptions prove to be incorrect. The following describes the accounting policies currently underlying our most significant financial statement items:

Contingencies

The financial results of the Company may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events.

Depreciation

Depreciation of property, plant, and equipment is recorded on a straight-line basis over the estimated useful lives. We assign asset lives based on reasonable estimates when an asset is placed into service. We periodically evaluate the estimated useful lives of our property, plant and equipment and revise our estimates. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. If any of these assumptions subsequently change, the estimated useful life of the asset could change and result in an increase or decrease in depreciation expense. Subsequent events could cause us to change our estimates, which would impact the future calculation of depreciation expense.

Property, Plant and Equipment

Property, plant, and equipment is recorded at historical cost of construction or, upon acquisition, the fair value of the assets acquired. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred. Expenditures to extend the useful lives of

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the assets or enhance their productivity or efficiency from their original design are capitalized over the expected remaining period of use. The carrying value of the assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. Sales or retirement of assets, along with the related accumulated depreciation, are removed from the accounts and any gain or loss on disposition is included in the statement of operations. Costs related to projects during construction, including interest on funds borrowed to finance the construction of facilities, are capitalized as construction in progress.

Impairment of Long-Lived Assets

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. Assets are tested 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 cash flows expected to result from the use and eventual disposal of the long-lived asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is determined using an income approach whereby the expected future cash flows are discounted using a rate management believes a market participant would assume is reflective of the risk associated with achieving the underlying cash flows.

Compensatory Awards

Certain of our current and former employees were granted Class B membership interests, classified as net profits interests, in DFW Midstream Management LLC or Summit Midstream Management, LLC. We refer to these interests collectively as the net profits interests. The net profits interests participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested net profits interests. The net profits interests are accounted for as compensatory awards. The net profits interests vest ratably over four to five years, 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 Midstream Partners LLC Agreement). With the assistance of a third-party valuation firm, we determined the fair value of the net profits interests as of the respective grant dates. The net profits interests were valued utilizing an option pricing method, which models the Class A and Class B membership interests as call options on the underlying equity value of either DFW Midstream Management LLC or Summit Midstream Management, LLC, and considers the rights and preferences of each class of equity in order to allocate a fair value to each class. We used a combination of the income and market approaches, including the following assumptions and internal and external factors in determining the grant date fair value of the net profits interests: (a) assumptions underlying the enterprise value used in connection 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, and terminal growth rates; (b) holding period restrictions; (c) discounts for lack of marketability; and (d) expected volatility rates based on the historical and implied volatility of other midstream services companies whose share or option prices are publicly available.

Revenue Recognition

We earn revenue from natural gas gathering services provided to natural gas producers and record such revenue as gathering services and other fees. We also earn revenue from the sale of physical natural gas retained from our customers to offset power expenses associated with electric-driven compression on the DFW Midstream system. We record this revenue as fuel retainage revenue. We record costs incurred which are reimbursed by our customers, on a gross basis in the consolidated statement of operations. Revenue is recognized when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price is fixed or determinable and (iv) collectability is reasonably assured.

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Our gas gathering agreements provide a monthly or annual minimum volume commitment, or MVC, from our customers. Under these monthly or annual MVCs, our customers agree to ship a minimum volume of natural gas on our gathering systems or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. If a customer's actual throughput volumes are less than its MVC for the applicable period, it must make a shortfall payment to us at the end of that contract month or year, as applicable. We recognize the revenue associated with MVC shortfall payments upon expiration of the applicable contract month or year. Under certain gas gathering agreements, our customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent periods to the extent that its throughput volumes in subsequent years exceed its MVC.

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INDUSTRY OVERVIEW

General

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

The following diagram illustrates the groups of assets commonly found along the natural gas value chain:

Midstream Services

The range of services utilized by midstream natural gas service providers are generally divided into the following categories:

Gathering

At the initial stages of the midstream value chain, a network of typically small diameter pipelines known as gathering systems directly connect to wellheads, pad sites or other receipt points in the production area. These gathering systems transport natural gas from the wellhead to downstream pipelines or a central location for treating and processing. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow for additional production and well connections without significant incremental capital expenditures.

Compression

Gathering systems are operated at design pressures that enable the maximum amount of production to be gathered from connected wells. Through a mechanical process known as compression,

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volumes of natural gas at a given pressure are compressed to a sufficiently higher pressure, thereby allowing those volumes to be delivered into a higher pressure downstream pipeline to be brought to market. Since wells produce at progressively lower field pressures as they age, it becomes necessary to add additional compression over time to maintain throughput across the gathering system.

Treating and Dehydration

Another process in the midstream value chain is treating and dehydration, a step that involves the removal of impurities such as water, carbon dioxide, nitrogen and hydrogen sulfide that may be present when natural gas is produced at the wellhead. These impurities must be removed for the natural gas to meet the specifications for transportation on long-haul intrastate and interstate pipelines. Moreover, end users will not purchase natural gas with a high level of these impurities. To meet downstream pipeline and end user natural gas quality standards, the natural gas is dehydrated to remove the saturated water and is chemically treated to separate the impurities from the natural gas stream.

Processing

The principal components of natural gas are methane and ethane, but most natural gas also contains varying amounts of other NGLs, which are heavier hydrocarbons that are found in some natural gas streams. Even after treating and dehydration, most natural gas is not suitable for long-haul intrastate and interstate pipeline transportation or commercial use because it contains NGLs, as well as natural gas condensate. This natural gas, referred to as liquids-rich natural gas, must be processed to remove these heavier hydrocarbon components, as well as natural gas condensate. NGLs not only interfere with pipeline transportation, but are also valuable commodities once removed from the natural gas stream. The removal and separation of NGLs usually takes place in a processing plant using industrial processes that exploit differences in the weights, boiling points, vapor pressures and other physical characteristics of NGL components.

Fractionation

The mixture of NGLs that results from natural gas processing is generally comprised of the following five components: ethane, propane, normal butane, iso-butane and natural gasoline. This mixture is often referred to as y-grade or raw make NGL. Fractionation is the process by which this mixture is separated into the NGL components prior to their sale to various petrochemical and industrial end users.

Transportation and Storage

Once the raw natural gas has been treated or processed and the raw NGL mix fractionated into individual NGL components, the natural gas and NGL components are stored, transported and marketed to end-use markets. Each pipeline system typically has storage capacity located both throughout the pipeline network and at major market centers to help temper seasonal demand and daily supply-demand shifts.

Contractual Arrangements

Midstream natural gas services, other than transportation and storage, are usually provided under contractual arrangements that vary in the amount of commodity price risk they carry. Three typical types of contracts are described below.

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Fee-Based

Under fee-based arrangements, the service provider typically receives a fee for each unit of natural gas gathered and compressed at the wellhead and an additional fee per unit of natural gas treated or processed at its facility. As a result, the service provider bears no direct commodity price risk exposure.

Percent-of-Proceeds

Under these arrangements, the service provider typically remits to the producers either a percentage of the proceeds from the sale of residue gas and/or NGLs or a percentage of the actual residue gas and/or NGLs at the tailgate. These types of arrangements expose the gatherer/processor to commodity price risk, as the revenues from the contracts directly correlate with the fluctuating price of natural gas and NGLs.

Keep-Whole

Under these arrangements, the service provider keeps 100% of the NGLs produced, and the processed natural gas, or value of the natural gas, is returned to the producer. Since some of the natural gas is used and removed during processing, the processor compensates the producer for the amount of natural gas used and removed in processing by supplying additional natural gas or by paying an agreed-upon value for the natural gas utilized. These arrangements have the highest commodity price exposure for the processor because the costs are dependent on the price of natural gas and the revenues are based on the price of NGLs.

There are two forms of contracts utilized in the transportation and storage of natural gas:

Firm

Firm service requires the reservation of pipeline capacity by a customer between certain receipt and delivery points. Firm customers generally pay a "demand" or "capacity reservation" fee based on the amount of capacity being reserved, regardless of whether the capacity is used, plus a usage fee based on the amount of natural gas gathered. Firm storage contracts involve the reservation of a specific amount of storage capacity, including injection and withdrawal rights, and generally include a capacity reservation charge based on the amount of capacity being reserved plus an injection and/or withdrawal fee.

Interruptible

Interruptible service is typically short-term in nature and is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers pay only for the volume of gas actually transported or stored. The obligation to provide this service is limited to available capacity not otherwise used by firm customers, and as such, customers receiving services under interruptible contracts are not assured capacity on the pipeline or at the storage facility.

Market Fundamentals

Natural Gas Demand

Natural gas is a significant component of energy consumption in the United States. According to the EIA, natural gas consumption accounted for approximately 25% of all energy used in the United States in 2010, representing 24 Tcf of natural gas. The EIA estimates that over the next 25 years, total domestic energy consumption will increase by over 10%, with natural gas consumption directly benefiting from population growth, growth in cleaner-burning natural gas-fired electric generation and

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natural gas vehicles. The following charts show the allocation of natural gas usage by end user as well as the relative position of natural gas as a power generation fuel source as of 2010.


Natural Gas Usage by End User		Power Generation Fuel Sources

Source: EIA, Annual Energy Outlook 2012 Early Release (January 2012).

According to the EIA, as shown in the chart below, during the period from 2001 through 2010, natural gas consumption increased by 9.6% overall from an average of approximately 60.9 Bcf/d in 2001 to an average of approximately 66.8 Bcf/d in 2011. Although the change in consumption levels during this period was variable on a year-to-year basis, growth was highest in the seasonal and weather-sensitive electric power generation and commercial/residential sectors, where consumption grew by approximately 42.3% and 1.3%, respectively. The growth in these sectors was partially offset by an approximate 7.6% decline in natural gas consumption in the less seasonal industrial sector.

U.S. Annual & Average Daily Natural Gas Consumption

Source: EIA, U.S. Natural Gas Consumption by End Use (April 2012).

Forecasts published by the EIA and other industry sources anticipate that long-term domestic demand for natural gas will continue to grow, and that the historical trend of growth in natural gas demand from seasonal and weather-sensitive consumption sectors will continue. These forecasts are supported by various factors, including (i) expectations of continued growth in the U.S. gross domestic product, which has a significant influence on long-term growth in natural gas demand; (ii) an increased

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likelihood that regulatory and legislative initiatives regarding domestic carbon policy will drive greater demand for cleaner burning fuels like natural gas; (iii) increased acceptance of the view that natural gas is a clean and abundant domestic fuel source that can lead to greater energy independence for the United States by reducing its dependence on imported petroleum; (iv) the emergence of low-cost natural gas shale developments, which suggest ample supplies and which are expected to keep natural gas prices low relative to crude oil prices, making the commodity attractive as a feedstock; and (v) continued growth in electricity generation from intermittent renewable energy sources, primarily wind and solar energy, for which natural-gas fired generation is a logical back-up power supply source. According to the EIA, natural gas consumption is expected to rise from 24.3 Tcf in 2010 to 26.5 Tcf in 2035.

Natural Gas Supply

Domestic natural gas consumption is currently satisfied primarily by production from conventional onshore and offshore production in the lower 48 states, as supplemented by production from historically declining pipeline imports from Canada, imports of LNG from foreign sources, and some Alaska production. In order to maintain current levels of U.S. natural gas supply and to meet the projected increase in demand, new sources of domestic natural gas must continue to be developed to offset depletion associated with mature, conventional production as well as the uncertainty of future LNG imports and infrastructure challenges associated with sourcing additional production from Alaska. Over the past several years, a fundamental shift in production has emerged with the contribution of natural gas from unconventional resources (defined by the EIA as natural gas produced from shale formations and coalbeds) increasing from 9.5% of total U.S. natural gas supply in 2000 to 32.4% in 2010. According to EIA data, during the three-year period from January 2007 through December 2010 domestic production of natural gas increased by an average of approximately 3.8% per annum, largely due to continued development of shale resources. The emergence of shale plays has resulted primarily from advances in horizontal drilling and hydraulic fracturing technologies, which have allowed producers to extract significant volumes of natural gas from these plays at cost-advantaged per unit economics versus most conventional plays.

In 2011, the EIA estimated that the United States held 827 Tcf of technically recoverable shale gas resource. As the depletion of onshore conventional and offshore resources continues, natural gas from unconventional resource plays is forecasted to fill the void and continue to gain market share from higher-cost sources of natural gas. As shown in the graph below, natural gas production from the major shale formations is forecast to provide the majority of the growth in domestically produced natural gas supply, increasing to approximately 49% in 2035 as compared with 23% in 2010.

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Natural Gas Production by Source, 1990-2035

Source: EIA, Annual Energy Outlook 2012 Early Release (January 2012).

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BUSINESS

Overview

We are a growth-oriented limited partnership focused on owning and operating midstream energy infrastructure that is strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in North America. We currently provide fee-based natural gas gathering and compression services in two unconventional resource basins: (i) the Piceance Basin, which includes the Mesaverde, Mancos and Niobrara Shale formations in western Colorado; and (ii) the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas. As of May 31, 2012, our gathering systems had approximately 386 miles of pipeline and 147,600 horsepower of compression. During the first quarter of 2012, our systems gathered an average of approximately 908 MMcf/d of natural gas, of which approximately 62% contained NGLs that were extracted by a third party processor. We believe that we are positioned to grow through the increased utilization and further development of our existing assets. In addition, we intend to grow our business through strategic partnerships with large producers to provide midstream services for their upstream development projects, as well as through acquisitions in our existing areas of operation and in new areas.

We generate a substantial majority of our revenue under long-term fee-based, natural gas gathering agreements. Our customers include some of the largest natural gas producers in North America, such as Encana Corporation, Chesapeake Energy Corporation, TOTAL, S.A., Carrizo Oil & Gas, Inc., WPX Energy, Inc., Bill Barrett Corporation, Exxon Mobil Corporation and EOG Resources, Inc.

Substantially all of our gas gathering agreements are underpinned by areas of mutual interest, or AMIs, and minimum volume commitments. Our AMIs cover approximately 330,000 acres in the aggregate, have original terms that range from 10 years to 25 years, and provide that any production from natural gas wells drilled by our customers within the AMIs will be shipped on our gathering systems. The minimum volume commitments, which totaled 2.6 Tcf at March 31, 2012 and, through 2020, average approximately 643 MMcf/d, are designed to ensure that we will generate a certain amount of revenue from each customer over the life of the respective gas gathering agreement, whether by collecting gathering fees on actual throughput or from cash payments to cover any minimum volume commitment shortfall. Our minimum volume commitments have original terms that range from 7 years to 15 years and, as of March 31, 2012, had a weighted average remaining life of 11.6 years assuming minimum throughput volume for the remainder of the term. The fee-based nature of these agreements enhances the stability of our cash flows by limiting our direct commodity price exposure.

We were formed in 2009 by members of our management team and Energy Capital Partners, which together with its affiliated funds, is a private equity firm with over $7.0 billion in capital commitments that is focused on investing in North America's energy infrastructure. We are currently owned by Energy Capital Partners, GE Energy Financial Services, a global investor in essential, long-lived and capital intensive energy assets with over $20 billion in energy investments worldwide, and certain members of our management team.

Our assets currently consist of two natural gas gathering systems, the Grand River system in western Colorado and the DFW Midstream system in north-central Texas. These systems are summarized below.

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Grand River System

The Grand River system primarily gathers natural gas produced by our customers from the liquids-rich Mesaverde formation within the Piceance Basin. The Mesaverde is a shallow, tight sands geologic formation that producers have targeted with directional drilling activities for several decades. The Grand River system also gathers natural gas produced from our customers' wells targeting the deeper Mancos and Niobrara Shale formations, which have higher initial production rates and lower Btu gas content than Mesaverde wells. Over the last two years, our customers have completed numerous horizontal wells targeting the emerging Mancos and Niobrara Shale formations. Based on our customers' current drilling expectations, we anticipate the majority of our near-term throughput on the Grand River system will continue to be comprised of Mesaverde formation production.

DFW Midstream System

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Business Strategies

Our principal business strategy is to increase the amount of cash distributions we make to our unitholders over time. Our plan for executing this strategy includes the following key components:

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Increasing capacity of and throughput volumes on our existing systems. We intend to continue to focus on maximizing the utilization of our assets by increasing volume throughput from existing customers and connecting new customers to our systems. The DFW Midstream system is designed to benefit from incremental volumes arising from high-density, infill drilling on existing pad sites that are already connected to the DFW Midstream system and do not require significant additional capital expenditures. In addition, we seek to optimize our existing systems by adding third-party volumes that in general would not otherwise be pursued by large upstream producers who are primarily focused on gathering their own production volumes.

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Capitalizing on organic growth opportunities. Our existing gathering systems provide us with significant organic expansion opportunities. We intend to leverage our management team's expertise in constructing, developing and optimizing midstream infrastructure assets to grow our business through organic development projects that are designed to extend our geographic reach, diversify our customer base, increase the number of our natural gas receipt points and maximize volume throughput. Our expansion of the DFW Midstream system is expected to increase the system to approximately 120 miles of 8 inch to 30 inch pipeline and 56,100 horsepower of electric-drive compression. This expansion includes installing additional electric-drive compression that we expect will increase throughput capacity on the DFW Midstream system from 410 MMcf/d to over 450 MMcf/d. We expect that this incremental throughput capacity will be utilized by our existing customers who we expect to drill on previously connected pad sites and new pad sites that we will connect to our system. We expect pad site connections to increase from 62 as of April 2012 to 73 by the end of 2013. Additional projects that we expect to undertake during 2012 include:

•: Connecting five pad sites adjacent to the DFW Midstream system for our new customer, Beacon E&P.
•: Continuing the construction of a new medium-pressure gathering system alongside portions of our existing low-pressure system in the Piceance Basin. In connection with our acquisition of the Grand River system, we entered into a contractual arrangement with Encana related to the development of midstream infrastructure to support Encana's emerging Mancos and Niobrara Shale development.
•: Pursuing new customers currently operating in close proximity to our existing gathering infrastructure in the Barnett Shale and the Piceance Basin in order to maximize system capacity utilization. We have successfully pursued this strategy since acquiring the DFW Midstream system in 2009 and it is highlighted by our addition of EOG, Vantage Energy and Beacon E&P as new customers in 2009, 2010 and 2012, respectively. We will continue to pursue this strategy in the Barnett Shale and the Piceance Basin and are currently in discussions with multiple producers to expand our asset footprint and increase our natural gas receipt points.

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Maintaining our focus on fee-based revenue with minimal direct commodity price exposure. As we expand our business, we intend to maintain our focus on providing midstream energy services under fee-based arrangements. Our midstream services are almost exclusively provided under long-term, fee-based contracts with original terms ranging from 10 years to 25 years. We do not take title to the natural gas that we gather for our customers and, as a result, our business is not directly exposed to commodity price fluctuations. In addition, we have secured AMIs from certain of our customers covering all of their natural gas production from approximately 230,000 acres in the Piceance Basin and 100,000 acres in the Barnett Shale. We believe that our

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focus on fee-based revenues with minimal direct commodity exposure is essential to maintaining stable cash flows and increasing our quarterly distributions over time.

•: Partnering with large natural gas producers to provide midstream services for their development projects in high-growth, unconventional resource plays. We pursue opportunities to partner with established producers in unconventional resource basins to develop new infrastructure that we believe will complement our existing midstream assets or enhance our overall business by facilitating our entry into new basins. These opportunities generally consist of a strategic acreage position in an unconventional resource play and represent assets that are well-positioned for accelerated production growth but have minimal existing midstream energy infrastructure to support such growth. We have been successful with this strategy and will continue to pursue similar opportunities that utilize our management team's experience in constructing, developing and operating large scale midstream infrastructure. We seek to promote commercial relationships with established producers, such as Encana on the Grand River system and Chesapeake on the DFW Midstream system, who are willing to serve as an anchor customer and are willing to commit to long-term volume and AMIs.
•: Diversifying our asset base by exploring acquisition and development opportunities in various geographical areas and other sectors of the midstream industry. While our natural gas gathering operations in the Piceance Basin and the Barnett Shale currently represent our core business, we intend to diversify our business into other sectors of the midstream industry such as crude oil gathering, storage and transportation, through both greenfield development projects and acquisitions, and into other geographic regions. We and our sponsors are frequently involved in discussions with third parties regarding the purchase of natural gas and crude oil midstream energy infrastructure assets. Working together with our sponsors, we intend to continue to evaluate opportunities to acquire or develop other midstream energy infrastructure assets that complement our existing business and allow us to leverage our asset base and our management team's development and industry expertise.

Competitive Strengths

We believe that we will be able to execute the components of our principal business strategy successfully because of the following competitive strengths:

•

Strategically located assets in core areas of prolific unconventional basins supported by existing partnerships with large producers to provide midstream services for their development projects. Our midstream energy infrastructure assets are strategically positioned within the core areas of two established unconventional resource plays. The formations in the basins served by our assets have relatively low drilling and completion costs. We believe that producers will continue their drilling and completion activities in the core areas of unconventional natural gas shale basins even if natural gas prices do not increase significantly from current levels because the return economics associated with core-area wells remain favorable in lower pricing environments compared to more marginal areas of production. We believe that continued drilling activity in these basins positions us to pursue attractive growth opportunities by further developing and optimizing our systems and by developing or acquiring complementary systems within our geographic areas of operation.

•: Grand River system.The Grand River system is located in the Piceance Basin and currently serves the established liquids-rich Mesaverde formation and is optimally located for expansion to serve the emerging Mancos and Niobrara Shale formations. In the Piceance Basin, production from the emerging Mancos and Niobrara Shale formations has only recently begun, as producers have started drilling wells in these formations in the last two years. We are constructing a new medium-pressure gathering system to service anticipated higher pressure gas production from the emerging Mancos and Niobrara Shale formations.

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•: DFW Midstream system.The DFW Midstream system is primarily located in southeastern Tarrant County, Texas, currently the largest natural gas producing county in the state. We consider this area to be the "core of the core" of the Barnett Shale because of the quality of the geology and the high production profile of the wells drilled to date. We believe that the AMIs underpinning our system are substantially undeveloped compared to other areas in the Barnett Shale due to the lack of historical gathering infrastructure in this area and limited associated drilling activity. We believe that our AMIs and our system footprint provide us with a competitive advantage to add additional producers and incremental volumes in this growing area of the Barnett Shale at a competitive capital cost.

•: Fee-based revenues underpinned by long-term contracts. A substantial majority of our revenue for the year ended December 31, 2011 was generated under long-term, fee-based gas gathering agreements. Several of our customers are among the largest producers in each of our areas of operation. In the Piceance Basin, we have a 25-year AMI covering approximately 187,000 acres and a 15-year minimum volume commitment with Encana for approximately 1.5 Tcf. Together with our other gas gathering agreements with producers in the Piceance Basin, we have AMIs covering approximately 230,000 acres, average minimum volume commitments of 498 MMcf/d through 2020 and total volume commitments of almost 2.1 Tcf in the Piceance Basin through 2026. Our gas gathering agreements with our Barnett Shale customers have AMIs covering approximately 100,000 acres in the high-growth core area of the Barnett Shale and minimum volume commitments of approximately 463 Bcf through 2020. We believe that having long-term, fee based gas gathering agreements with minimal direct commodity price exposure enhances the predictability of our performance.
•: Capital structure and financial flexibility. At the closing of this offering, we expect to have approximately $ million of borrowing capacity available to us under our amended and restated revolving credit facility. We believe our borrowing capacity and our ability to access private and public debt and equity capital will provide us with the requisite financial flexibility to execute our growth and expansion strategy.
•: Experienced management team with proven record of asset acquisition, construction, development, operation and integration expertise. Our executive management team has an average of 16 years of energy experience and a proven track record of identifying and consummating significant acquisitions in addition to partnering with major producers to construct and develop midstream infrastructure. As demonstrated by our current business, our management team has demonstrated particular expertise in constructing new—and 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 energy projects.
•: Relationships with large and committed financial sponsors. Our sponsors, Energy Capital Partners and GE Energy Financial Services, are experienced energy investors with proven track records of making substantial, long-term investments in high-quality midstream energy assets. Energy Capital Partners has indicated that it intends to use us as its primary platform for the acquisition, construction and development of future midstream infrastructure assets; however, it is not obligated to do so. While there are no assurances that we will benefit from our relationship with our sponsors, we believe our relationship with both of our sponsors will be a competitive advantage, as they both bring not only significant financial and management experience, but also numerous relationships throughout the energy industry that we believe will benefit us as we seek to grow our business. In addition, we believe that Energy Capital Partners and GE Energy Financial Services, as the indirect owners of our general partner interest, all of our incentive distribution rights and a % limited partner interest in us, will be motivated to promote and support the successful execution of our business strategies.

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Our Sponsors

We were 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 $7.0 billion in capital commitments that is focused on investing in North America's energy infrastructure. Energy Capital Partners has significant energy and financial expertise to complement its investment in us. To date, Energy Capital Partners has formed 21 investment platforms across its funds with investments in the power generation, electric transmission, midstream natural gas and renewable sectors of the energy industry. In August 2011, Energy Capital Partners sold an interest in Summit Investments to GE Energy Financial Services. GE Energy Financial Services invests globally in essential, long-lived and capital-intensive energy assets. To date, GE Energy Financial Services has invested over $20 billion in energy investments worldwide, of which approximately $2.4 billion has been committed to midstream-related portfolio companies.

Our Assets

Our assets currently consist of two natural gas gathering systems, the Grand River system in western Colorado and the DFW Midstream system in north-central Texas. These systems are discussed in more detail below.

Grand River System

The following table provides information regarding our Grand River system as of May 31, 2012.

Formation(s) Served		Approximate Length (Miles)			Approximate Number of Wells Serviced			Compression (Horsepower)			Approximate AMI (Acres)			Remaining Volume Commitment (Bcf)(1)			Throughput Capacity (MMcf/d)			Average Throughput (MMcf/d)(1)

Mesaverde, Mancos and Niobrara			276			1,720	(2)		97,500			230,000			2,104			885			593

(1): As of the quarter ended March 31, 2012.
(2): Excludes wells connected to nine central receipt points that represent an aggregate of 250 MMcf/d.

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In October 2011, we acquired the Grand River system from Encana for $590 million. The Grand River system is primarily located in Garfield County, Colorado, the largest natural gas producing county in Colorado, and comprises approximately 276 miles of 3 inch to 24 inch diameter pipeline and approximately 97,500 horsepower of compression. The Grand River system gathers natural gas from the Mesaverde, Mancos and Niobrara Shale formations located within the Piceance Basin. All of the natural gas volumes gathered on the Grand River system are discharged to third-party pipelines that deliver to Enterprise Products Partners L.P.'s 1.7 Bcf/d processing facility located in Meeker, Colorado.

The Grand River system has total throughput capacity of 885 MMcf/d and for the quarter ended March 31, 2012 gathered an average of approximately 593 MMcf/d. The system gathers production from the Mamm Creek, South Parachute and Orchard fields in the area around Rifle, Colorado. The Grand River system is underpinned by long-term, fee-based gas gathering agreements with Encana, WPX Energy, Bill Barrett Corporation and Antero Resources that include minimum volume commitments with original terms ranging from 10 to 15 years and AMIs with original terms ranging from 10 years to 25 years. As of March 31, 2012, these gas gathering agreements had remaining minimum volume commitments totaling approximately 2.1 Tcf over the next 15 years, an average of approximately 498 MMcf/d through 2020, and AMIs covering approximately 230,000 acres for terms of up to 25 years. Our customers do not have leases that currently cover our entire AMIs in the Piceance Basin but, to the extent our customers lease additional acreage in the future within those AMIs, natural gas produced by our customers from that leased acreage will be gathered by the Grand River system. For a more detailed description of these gas gathering agreements, please read "—Gas Gathering Agreements."

The Grand River system is currently a low-pressure gathering system that was originally designed to gather natural gas produced from traditional vertical wells focused on the shallower, higher-Btu Mesaverde formation. Our largest Grand River customer, Encana, currently has approximately 1,720 wells on approximately 375 pad sites connected to our existing low-pressure gathering system. We also receive natural gas from other producer customers at nine central receipt points on the Grand River

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system. We expect to continue to pursue additional volumes on the low-pressure system to more fully utilize the existing available throughput capacity.

In connection with our acquisition of the Grand River system, we entered into a contractual relationship with Encana related to the development of midstream infrastructure to support Encana's emerging Mancos and Niobrara Shale development.

DFW Midstream System

The following table provides information regarding our DFW Midstream system as of May 31, 2012.

Formation(s) Served		Approximate Length (Miles)			Approximate Number of Wells Serviced			Compression (Horsepower)			Approximate AMI (Acres)			Remaining Volume Commitment (Bcf)(1)			Throughput Capacity (MMcf/d)			Average Throughput (MMcf/d)(1)

Barnett			110			310			50,100			100,000			463			410			315

(1): As of the quarter ended March 31, 2012.

The DFW Midstream system is located within the primarily urban environment of southeastern Tarrant County, Texas, which resides within the Fort Worth Basin and includes the Barnett Shale geologic formation. We consider this area to be the "core of the core" of the Barnett, which, according to the Texas Railroad Commission, contains the most prolific wells, including the two largest and four of the ten largest wells drilled to date, in the Barnett Shale based on peak month daily average

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production rates. The DFW Midstream system, which has been under construction since 2008, includes gathering lines ranging from 8 inches to 30 inches in diameter and is located along existing electric transmission corridors and under both private and municipal property. The system currently has five primary interconnections with third-party, intrastate pipelines that enable us to connect our customers with downstream pipelines serving the established Waha, Carthage and Perryville natural gas market hubs in Texas and Louisiana.

Our development of the DFW Midstream system is underpinned by seven long-term, fee-based gas gathering agreements with Chesapeake, TOTAL, Carrizo, Atlas Energy, EOG, Exxon Mobil and Vantage. As of March 31, 2012, these gas gathering agreements have remaining minimum volume commitments totaling approximately 463 Bcf and average, through 2020, approximately 145 MMcf/d. In addition, these gas gathering agreements have AMIs that cover approximately 100,000 acres through 2030. Our customers do not have leases that currently cover our entire AMIs in the Barnett Shale but, to the extent our customers lease additional acreage in the future within those AMIs, natural gas produced by our customers from that leased acreage will be gathered by the DFW Midstream system. For a more detailed description of these gas gathering agreements, please read "—Gas Gathering Agreements."

We have owned and operated the DFW Midstream system since 2009, when we acquired it from Energy Future Holdings and concurrently acquired certain complimentary pipeline and other related gathering system assets from Chesapeake. We simultaneously entered into a long-term gas gathering agreement with Chesapeake as our anchor customer that included a 20-year AMI covering approximately 95,000 acres and a 10-year minimum volume commitment totaling approximately 450 Bcf. At the time of the acquisition, the DFW Midstream system had average throughput of approximately 10 MMcf/d and had approximately 17 miles of pipeline and 2,500 horsepower of installed electric-drive compression in service.

Since the acquisition, we have expanded the DFW Midstream system by adding approximately 93 miles of additional pipeline and 47,600 horsepower of electric-drive compression. For the quarter ended March 31, 2012, the DFW Midstream system had average throughput of approximately 315 MMcf/d. We continue to develop the DFW Midstream system to extend our gathering reach, diversify our customer base, increase our receipt points and maximize throughput on the system. In 2012, we intend to continue to connect additional pad sites located within our AMIs and expand the throughput capacity from 410 MMcf/d to over 450 MMcf/d by installing additional electric-drive compression. The system will include approximately 120 miles of low- and high-pressure gathering lines and 56,100 horsepower of electric-drive compression. As of May 31, 2012, approximately 310 wells on 62 pad sites were connected to the DFW Midstream system and 34 additional wells were in various stages of completion, 29 of which are on existing pad sites that we currently serve and 5 of which are on pad sites to which we intend to connect.

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 natural gas gathering infrastructure. The DFW Midstream system, which is primarily located in southeast Tarrant County, has addressed the historical lack of gathering infrastructure and currently provides producers in the area with a safe, efficient and reliable solution to deliver their natural gas to market. Tarrant County, which is currently the largest natural gas producing county in Texas, experienced an increase in natural gas production from 1.6 Bcf/d in October 2009 to 2.0 Bcf/d in October 2011. Over this same period, throughput on the DFW Midstream system increased from approximately 10 MMcf/d to approximately 380 MMcf/d, which accounted for approximately 90% of Tarrant County's increased natural gas production.

We believe the production profile of wells drilled within our AMIs, which includes the two largest wells ever drilled in the Barnett Shale, will continue to attract drilling activity over the long term as

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producers become more selective in their drilling locations in order to maximize their returns. We also believe that the acreage dedicated to the DFW Midstream system is substantially undeveloped as evidenced by our 100,000 acre gathering footprint and our customers' desire to reduce well spacing below 50 acres to maximize recoverable reserves. We believe our strategic location in the core of the core of the Barnett Shale provides us with a competitive advantage to add incremental throughput with limited additional investment capital due to the anticipated future, high-density, infill drilling from our customers on connected pad sites and nearby pad sites that have yet to be connected. This high-density, infill drilling, is magnified in our area given the urban landscape and the desire of our producer customers to minimize their surface footprint.

Gas Gathering Agreements

We derive revenue primarily from long-term, fee-based, gas gathering agreements, or GGAs, with some of the largest and most active producers in our areas of operation. The following describes the material provisions included in the majority of our firm gas gathering agreements with our significant customers, including our natural gas gathering agreements with Chesapeake, Encana, Carrizo Oil and Gas and WPX Energy.

AMIs and Contract Terms

Our gas gathering agreements contain AMIs. The AMIs generally have original terms that range from 10 years to 25 years and require that any production by our customers within the AMIs will be shipped on gathering systems. Under certain of our GGAs, we have agreed to construct pipeline laterals to connect our gathering systems to pad sites located within the AMI. If we choose to forego a discretionary opportunity presented by the customer, such as constructing a lateral to an additional pad site, or constructing additional pipeline infrastructure or related assets in connection with a customer's expansion of its drilling operations, the customer may, in certain circumstances, construct the additional infrastructure and sell it to us at a price equal to their cost plus an applicable margin, or, in some cases, release the relevant acreage dedication from the AMI.

Minimum Volume Commitments

Our gas gathering agreements contain minimum volume commitments, or MVCs, pursuant to which our customers guarantee to ship a minimum volume of natural gas on our gathering systems, or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. The original terms of the MVCs range from 7 to 15 years. In addition, certain of our customers have an aggregate MVC, which is a total amount of natural gas that the customer must transport on our gathering systems (or an equivalent monetary amount) over the MVC term. In these cases, once a customer achieves its aggregate MVC, any remaining future MVCs will terminate and the customer will then simply pay the applicable gathering rate multiplied by the actual throughput volumes shipped.

If a customer's actual throughput volumes are less than its MVC for the applicable period, it must make a shortfall payment to us at the end of that contract month or year, as applicable. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped for the applicable period and the MVC for the applicable period, multiplied by the applicable gathering fee. To the extent that a customer's actual throughput volumes are above or below its MVC for the applicable period, however, many of our GGAs contain provisions that can operate to reduce or delay the cash flows that we expect to receive from our MVCs. These provisions include the following:

•: To the extent that a customer's throughput volumes are less than its MVC for the applicable period and the customer makes a shortfall payment, it is entitled to an offset in one or more subsequent periods to the extent that its throughput volumes in subsequent periods exceed its MVC for those periods. In such a situation, we would not receive gathering fees on throughput in excess of a customer's monthly or annual MVC (depending on the terms of the specific gas

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gathering agreement) to the extent that the customer had made a shortfall payment with respect to one or more preceding months or years (as applicable).

•: To the extent that a customer's throughput volumes exceed its MVC in the applicable period, it is entitled to apply the excess throughput against its aggregate MVC, thereby reducing the period for which its annual MVC applies. For example, one of our DFW Midstream customers has a contracted MVC term from October 2010 through September 2017. However, this customer has regularly shipped excess natural gas on our DFW Midstream system relative to its MVC. Assuming its throughput rate remains at this level, we estimate that it will satisfy the requirements of its aggregate MVC by the end of 2012, thereby reducing the period for which its MVC applies from eight years to less than three years. As a result of this mechanism, the weighted average remaining period for which our MVCs apply is less than the weighted average of the original stated terms of our MVCs.
•: To the extent that a customer's throughput volumes exceed its MVC for the applicable period, there is a crediting mechanism that allows the customer to build a "bank" of credits that it can utilize in the future to reduce shortfall payments owed in subsequent periods, subject to expiration if there is no shortfall payment owed in subsequent periods. The period over which this credit bank can be applied to future shortfall payments varies, depending on the particular GGA.

Fuel Retainage Fees and Cost Pass-Throughs

Our GGAs on our DFW Midstream system allow us to retain a small fixed percentage of the natural gas that we receive at the receipt points to offset the costs we incur to operate our electric-drive compressors. On average, we retain nominal amounts of the natural gas received at the receipt points on the DFW Midstream system. Our GGAs on our Grand River system allow us to (i) charge our customers for the electricity costs we incur to operate our electric-drive compressors and (ii) utilize physical gas on the Grand River system to operate our gas-fired compressors.

Pressure Variance Penalties

Our GGAs require us to maintain certain specified operating pressures on our gathering systems, both on a system-wide basis and with respect to each receipt point. We are also required to maintain certain minimum operating pressures at certain of our compressor stations. If we fail to maintain our required system and receipt point operating pressures, we can be subject to penalties in the form of substantial reductions in our gathering fees (subject, in certain circumstances, to force majeure relief). These reductions generally range from 25% to 75%, depending on the duration of the pressure variance. With respect to compressor station pressure variances, we are subject to penalties in the form of loss of our fuel retainage fees and our ability to pass our electricity costs on to the customer for a period of time, depending on the duration of the pressure variance. With respect to system and receipt point pressure variances that persist for extended periods of time (generally exceeding four months in any consecutive twelve month period), our customers are entitled to additional remedies, including:

•: a 100% reduction in gathering fees applicable to future shipments until the end of the first month following the resolution of the pressure variance; and
•: the ability to release all or a portion of the customer's future gas production from the GGA.

Competition

The natural gas gathering, compression and transportation business is very competitive. Our competitors include other midstream companies, producers and intrastate and interstate pipelines. Competition for natural gas volumes is primarily based on reputation, commercial terms, reliability, service levels, flexibility, access to end-use markets, location, available capacity, capital expenditures and

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fuel efficiencies. Our principal competitors in the Fort Worth Basin are Chesapeake Midstream Partners, L.P., Crestwood Midstream Partners LP and Energy Transfer Partners, L.P. Our principal competitors in the Piceance Basin are Williams Partners L.P., Energy Transfer Partners, L.P. and Enterprise Products Partners L.P.

In the future, we may face competition for production drilled outside of our AMIs and on attracting third-party volumes to our systems. Additionally, to the extent we make acquisitions from third parties we could face incremental competition.

Safety and Maintenance

We are subject to regulation by DOT under the Natural Gas Pipeline Safety Act of 1968, as amended, also known as the NGPSA, which establishes federal safety standards for the design, construction, operation and maintenance of natural gas pipeline facilities. In the Pipeline Safety Act of 1992, also known as the PSA, Congress expanded DOT's regulatory authority to include "regulated gathering lines" that had previously been exempt from federal jurisdiction. The Pipeline Safety Improvement Act of 2002, also known as the PSIA, and the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, also known as the PIPES Act, established mandatory inspections for certain U.S. oil and natural gas transmission pipelines in high consequence areas, and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 reauthorizes funding for federal pipeline safety programs through 2015, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines.

DOT has delegated the implementation of safety requirements to PHMSA, which has adopted and enforces safety standards and procedures applicable to our pipelines. In addition, many states, including the states in which we operate, have adopted regulations, similar to existing DOT regulations for intrastate pipelines. Among the regulations applicable to us, PHMSA requires pipeline operators to develop integrity management programs for certain pipelines located in high consequence areas, which include high population areas such as the Dallas-Fort Worth greater metropolitan area where our DFW gathering system is located, areas that are sources of drinking water, ecological resource areas that are unusually sensitive to environmental damage from a pipeline release and commercially navigable waterways. While the majority of our pipelines meet the DOT definition of gathering lines and are thus exempt from PHMSA's integrity management requirements, we also operate three pipelines in the Dallas-Fort Worth area that are subject to the integrity management requirements. The regulations require operators, including us, to:

•: perform ongoing assessments of pipeline integrity;
•: identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
•: maintain processes for data collection, integration and analysis;
•: repair and remediate pipelines as necessary; and
•: implement preventive and mitigating actions.

While repairs, remediation or preventative or mitigation measures resulting from integrity management inspections could obligate us to make material expenditures, we do not anticipate such an outcome because our pipelines are relatively new.

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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 gathering lines. Extending the integrity management requirements to our gathering lines would impose additional obligations on us and could add material costs to our operations.

We believe that we are in compliance with existing safety laws and regulations and we cannot predict the outcome of new regulatory initiatives; however, increased penalties for safety violations and potential regulatory changes could have a material effect on our operations, operating and maintenance expenses, and revenues.

We are also subject to a number of federal and state laws and regulations, including the Federal Occupational Safety and Health Act, or the OSHA, and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and citizens. We are also subject to the OSHA Process Safety Management regulations that are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling points without the benefit of chilling or refrigeration are exempt. We are also subject to EPA Chemical Accident Prevention Provisions, also known as the Risk Management Plan requirements, which are designed to prevent the accidental release of toxic, reactive, flammable or explosive materials. We have an internal program of inspection designed to monitor and enforce compliance with all of these requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety, community right to know laws, and the security of our facilities.

Regulation of the Oil and Natural Gas Industries

General

Sales by producers of natural gas, crude oil, condensate, and NGLs are currently made at uncontrolled market prices; however, regulation of gathering and transportation services may affect certain aspects of our business and the market for our services. FERC regulates the transportation of natural gas in interstate commerce and the interstate transportation of crude oil, petroleum products and NGLs. FERC regulation includes reviewing and accepting or approving rates and other terms and conditions for such transportation services. FERC and FTC are also authorized to prevent and sanction market manipulation in natural gas markets and petroleum markets, respectively. State and municipal regulations may apply to the production and gathering of natural gas, the construction and operation of natural gas and crude oil facilities, and the rates and practices of gathering systems and intrastate pipelines.

Regulation of Oil and Natural Gas Exploration, Production and Sales

Sales of crude oil and NGLs are not currently regulated and are transacted at market prices. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993. FERC, which has the authority under the NGA to regulate the prices and other terms and conditions of the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all gas resellers subject to FERC regulation, except interstate pipelines, to resell natural gas at market prices. Either

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Congress or FERC (with respect to the resale of gas in interstate commerce), however, could re-impose price controls in the future.

Exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits, bonds and pollution liability insurance for the drilling of wells, regulating the location of wells, the method of drilling, casing, operating, plugging and abandoning wells, and governing the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation of resources, including provisions for the unitization or pooling of producing properties, the establishment of maximum rates of production from wells, and the regulation of spacing of wells. These state and municipal regulations do not directly apply to our business, but may nonetheless affect the availability of natural gas for gathering by us.

Regulation of the Gathering and Transportation of Natural Gas

We believe that our gas pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of FERC under the NGA and the NGPA, although we are subject to FERC's anti-market manipulation regulations (seeAnti-Market Manipulation Rules below). The distinction between federally unregulated gathering facilities and FERC-regulated transmission pipelines has been the subject of extensive litigation and may be determined by FERC on a case-by-case basis, although FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of some of our pipelines could change based on future determinations by FERC or the courts. If our gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers.

Our gathering of natural gas is also affected by the availability, terms and cost of downstream transportation services. The rates and terms for access to pipeline transportation services are subject to extensive regulation. In recent years, FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of these initiatives, interstate natural gas transportation and marketing systems have been substantially restructured to remove barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from competing effectively with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. FERC's regulations require, among other things, that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas suppliers, provide internet access to current information about available pipeline capacity and other relevant information, and permit pipeline shippers to release contracted transportation and storage capacity to other shippers, thereby creating secondary markets for such services. The result of FERC's initiatives has been to eliminate the interstate pipelines' traditional role of providing bundled sales service of natural gas and to require pipelines to offer unbundled storage and transportation services on a non-discriminatory basis. The rates for such transportation and storage services are subject to FERC ratemaking authority, and FERC exercises its authority by applying cost-of-service principles, allowing for the negotiation of rates where there is a cost-based alternative rate or granting market-based rates in certain circumstances, typically with respect to storage services.

Natural gas production, gathering and transportation may be subject to state and local regulations that may change from time to time. Our construction of new gathering facilities and expansion of existing gathering facilities may be subject to state and local regulation, including approval and permit requirements. Regulation of our operations may cause us to incur additional operating costs or limit the quantities of gas we may gather. In addition, state ratable take statutes and regulations generally require us to take natural gas production that may be tendered to us for handling without undue discrimination. These statutes are designed to prohibit discrimination in favor of one source of supply over another source of supply and they restrict our right to decide whose production we gather.

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Gathering systems and pipelines that operate only in a single state may be subject to regulation by state regulatory authorities with respect to safety (under a federal certification) and rates and practices, including requirements for ratable takes or non-discriminatory access to pipeline services. The basis for state regulation and the degree of regulatory oversight of gathering systems and intrastate pipelines varies from state to state. In Texas, we have filed a tariff with the Texas Railroad Commission to establish rates and terms of service for our DFW operations. We have not been required to file a tariff in Colorado for our Grand River assets. Both of these states have adopted complaint-based regulation that allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve access issues and rate grievances, among other matters. State authorities generally have not initiated investigations of the rates or practices of gathering systems or intrastate pipelines in the absence of a complaint.

Intrastate pipelines that provide interstate transportation service are regulated by FERC under Section 311 of the NGPA as to rates and other terms and conditions of service with respect to interstate gas shipments, unless an exemption from such regulation applies (such as for gathering lines). We believe that our pipelines are gathering systems that are therefore exempt from Section 311 requirements.

Changes in federal, state, or local law or policy may affect us either directly or indirectly. While we cannot predict what further action legislators or regulators will take, we do not believe that any such action taken will affect us differently, in any material way, than other midstream companies with which we compete.

Regulation of Crude Oil and NGL Transportation Rates

In a number of instances the ability to transport and sell crude oil and NGLs is dependent on pipelines whose rates and other terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act and the Energy Policy Act of 1992, state regulatory jurisdiction under state statutes, or both. Interstate transportation rates for crude oil and NGLs, among other liquid commodities, are regulated by FERC, and, in general, these rates must be cost-based or based on rates in effect in 1992, although FERC has established an indexing system for such transportation rates which allows pipelines to take an annual inflation-based rate increase. Shippers may, however, contest rates that do not reflect costs of service. FERC has also established market-based rates and settlement rates as alternative forms of ratemaking in certain circumstances.

In other instances involving intrastate-only transportation of crude oil, NGLs and other products, the ability to transport and sell such commodities is dependent on transportation by pipelines at rates, and on other terms and conditions of service that are subject to regulation by state regulatory authorities. Such pipelines may be subject to state regulation with respect to safety (under a federal certification) and rates and other practices, including requirements for ratable takes or non-discriminatory access to pipeline services. The basis for state regulation and the degree of regulatory oversight of intrastate liquids pipelines varies from state to state. Many states operate on a complaint-based system and state authorities have generally not initiated investigations of the rates or practices of liquids pipelines in the absence of a complaint.

Anti-Market Manipulation Rules

We are subject to the anti-market manipulation provisions in the NGA, as amended by EPAct 2005, which authorize FERC to impose fines of up to one million dollars ($1,000,000) per day per violation of the NGA or its implementing regulations. In addition, FTC holds statutory authority under the EISA to prevent market manipulation in petroleum markets, including the authority to request that a court impose fines of up to one million dollars ($1,000,000) per day per violation. These agencies have promulgated broad rules and regulations prohibiting fraud and manipulation in oil and gas markets. The CFTC is directed under the CEA to prevent price manipulations for the commodity and

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futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Act and other authority, CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. CFTC also has statutory authority to seek civil penalties of up to the greater of one million dollars ($1,000,000) or triple the monetary gain to the violator for violations of the anti-market manipulation sections of CEA. We are also subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation. Failure to comply with such market rules, regulations and requirements could have a material adverse effect on our business, results of operations, and financial condition.

Environmental Matters

General

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

•: requiring the installation of pollution-control equipment or otherwise restricting the way we operate or imposing additional costs on our operations;
•: limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;
•: delaying system modification or upgrades during permit reviews;
•: requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and
•: enjoining the operations of facilities deemed to be in non-compliance with permits or permit requirements issued pursuant to or imposed by such environmental laws and regulations.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations.

We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability to gather, compress and transport natural gas. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion

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of the material environmental laws and regulations that relate to our business. We believe that we are in substantial compliance with all of these environmental laws and regulations.

Hazardous Substances and Waste

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, referred to as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. We may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

We also generate industrial wastes that are subject to the requirements of the Resource Conservation and Recovery Act, referred to as RCRA, and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. We generate little hazardous waste; however, it is possible that non-hazardous wastes, which could include wastes currently generated during our operations, will in the future be designated as "hazardous wastes" and, therefore, be subject to more rigorous and costly disposal requirements. Moreover, from time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for non-hazardous wastes, including natural gas wastes. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses or otherwise impose limits or restrictions on our operations or those of our customers.

We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although previous operators have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.

Oil Pollution Act (OPA)

In 1991, the EPA adopted regulations under the OPA. These oil pollution prevention regulations, as amended several times since their original adoption, require the preparation of a Spill Prevention Control and Countermeasure Plan, or SPCC, for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility's operations comply with the requirements. To be in compliance, the facility's SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacility piping), inspections and records, security, and training. Most

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importantly, the facility must fully implement the SPCC plan and train personnel in its execution. We believe that none of our facilities is materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

Air Emissions

Our operations are subject to the federal Clean Air Act and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We believe that we are in substantial compliance with these requirements. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

Increased obligations of operators to reduce air emissions of nitrogen oxides and other pollutants from internal combustion engines in transmission service have been enacted by governmental authorities. For example, on August 20, 2010, the EPA published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocating internal combustion engines. On May 22, 2012, the EPA proposed amendments to the final rule in response to several petitions for reconsideration. The EPA must finalize the proposed amendments by December 14, 2012. The rule will require us to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment, such as oxidation catalysts or non-selective catalytic reduction equipment, on all our engines following prescribed maintenance practices 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 rule and proposed amendments.

On June 28, 2011, the EPA issued a final rule, effective August 29, 2011 modifying existing regulations under the CAA that established new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The final rule may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment. Compliance with the final rule is not required until at least 2013. On May 22, 2012, the EPA proposed minor amendments which must be finalized by December 14, 2012. We are currently evaluating the impact that this final rule and proposed amendments will have on our operations.

On April 17, 2012, the EPA finalized rules that establish new air emission control requirements for oil and natural gas production and natural gas processing operations. Specifically, the EPA's rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules establish specific new requirements regarding emissions from compressors and controllers at natural gas processing plants, dehydrators, storage tanks and other production equipment. In addition, the rules establish new leak detection requirements for natural gas processing plants at 500 ppm. These rules will require a number of modifications to our operations, including the installation of new equipment to control emissions from our compressors at initial startup, or 60 days after the final rule is published in

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the Federal Register. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. In addition, the EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells, which may impact our customers. Before January 1, 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring using a completion combustion device or by capturing the gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured wells as well as existing wells that are refractured. These requirements may result in increased operating costs for producers who drill near our pipelines, which could reduce the volumes of natural gas available to move through our gathering systems, which could materially adversely affect our revenue and results of operations. For additional information about hydraulic fracturing and related environmental matters, please read "Business—Environmental Matters—Hydraulic Fracturing."

These new regulations and proposals, when finalized, and any other new regulations requiring the installation of more sophisticated pollution control equipment could have a material adverse impact on our business, results of operations, financial condition and ability to make cash distributions to our unit holders.

Water Discharges

The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the United States and impose requirements affecting our ability to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. We believe that compliance with existing permits and compliance with foreseeable new permit requirements under the Clean Water Act and state counterparts will not have a material adverse effect on our financial condition, results of operations or cash flow.

Hydraulic Fracturing

The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. We do not conduct any hydraulic fracturing activities, and we believe that our facilities will not be materially adversely affected by such requirements. However, a portion of our customers' natural gas production is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. We do not engage in any hydraulic fracturing activities although many of our customers do. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of "underground injection" and

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require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under the Act's Underground Injection Control Program to require disclosure of chemicals used in the hydraulic fracturing process. Scrutiny of hydraulic fracturing activities continues in other ways. The federal government is currently undertaking several studies of hydraulic fracturing's potential impacts, the results of which are expected between the latter part of 2012 and 2014. In addition, on October 21, 2011, the EPA announced its intention to propose regulations by 2014 under the federal Clean Water Act to regulate wastewater discharges from hydraulic fracturing and other natural gas production activities. On May 4, 2012, the BLM 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 BLM after fracturing operations have been completed and includes provisions addressing well-bore integrity and flowback water management plans.

Several states, including states in which our customers do business, such as Texas and Colorado, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing through additional permit requirements, public disclosure of fracturing fluid contents, operational restrictions, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. We cannot predict whether any other legislation will be enacted in the future and if so, what its provisions would be. If additional levels of regulation and permits are required through the adoption of new laws and regulations at the federal or state level, it could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of natural gas that move through our gathering systems which would materially adversely affect our revenue and results of operations. For additional information about hydraulic fracturing and related environmental matters, please read "Risk Factors—Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenues."

Endangered Species

The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans or limit future development activity in the affected areas.

National Environmental Policy Act

The National Environmental Policy Act, or NEPA, establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA and, as a result, many activities requiring FERC approval must undergo NEPA review. Many of our activities are covered under categorical exclusions which results in a shorter NEPA review process. The Council on Environmental Quality has announced an intention to reinvigorate NEPA reviews and on March 12, 2012, issued final guidance that may result in longer review processes that could lead to delays and increased costs that could materially adversely affect our revenues and results of operations.

Climate Change

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases" and including carbon dioxide and methane, may be contributing to warming of the Earth's atmosphere. In response to the scientific studies, international negotiations to address climate

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change have occurred. The United Nations Framework Convention on Climate Change, also known as the "Kyoto Protocol," became effective on February 16, 2005 as a result of these negotiations, but the United States did not ratify the Kyoto Protocol. At the end of 2009, an international conference to develop a successor to the Kyoto Protocol issued a document known as the Copenhagen Accord. Pursuant to the Copenhagen Accord, the United States submitted a greenhouse gas emission reduction target of 17 percent by 2020 compared to 2005 levels. We continue to monitor the international efforts to address climate change. Their effect on our operations cannot be determined with any certainty at this time.

In the United States, legislative and regulatory initiatives are underway to limit GHG emissions. The U.S. Congress has considered legislation that would control GHG emissions through a "cap and trade" program and several states have already implemented programs to reduce GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the federal Clean Air Act, or the CAA, definition of an "air pollutant," and in response the EPA promulgated an endangerment finding paving the way for regulation of GHG emissions under the CAA. In 2010, the EPA issued a final rule, known as the "Tailoring Rule," that makes certain large stationary sources and modification projects subject to permitting requirements for greenhouse gas emissions under the Clean Air Act.

In addition, in September 2009, the EPA issued a final rule requiring the reporting of GHGs from specified large GHG emission sources in the United States beginning in 2011 for emissions in 2010. On November 30, 2010, the EPA published a final rule expanding its existing GHG 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 GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. However, due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact that related developments will have on us.

Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher greenhouse gas emitting energy sources, our products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. Conversely, to the extent that our products are competing with lower greenhouse gas emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on greenhouse gas emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.

The majority of scientific studies on climate change suggest that stronger storms may occur in the future in the areas where we operate, although the scientific studies are not unanimous. We are taking steps to mitigate physical risks from storms, but no assurance can be given that future storms will not have a material adverse effect on our business.

Anti-terrorism Measures

The Department of Homeland Security Appropriation Act of 2007 requires the Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present "high levels of security risk." The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to this act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. Covered facilities that are determined by DHS to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements,

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including those regarding inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information.

Title to Properties and Rights-of-Way

Our real property falls into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our gathering systems and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our major facilities are located are held by us pursuant to perpetual easements between us and the underlying fee owner, or permits with governmental authorities. Our Predecessor leased or owned these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership in such lands or valid permits with governmental authorities. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses with the exception of certain permits with governmental entities that have been applied for, but not yet issued.

Employees

We do not have any employees. The officers of our general partner will manage our operations and activities. As of March 31, 2012, Summit Midstream Partners, LLC employed 73 people who provide direct, full-time support to our operations, including 19 field-level employees we hired from Encana in connection with our acquisition of the Grand River system. Subsequent to the closing of this offering, all of the employees required to conduct and support our operations will be employed by our general partner or its affiliates. None of these employees are covered by collective bargaining agreements, and our general partner considers its employee relations to be good.

Legal Proceedings

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

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MANAGEMENT

Management of Summit Midstream Partners, LP

We are managed by the directors and executive officers of our general partner, Summit Midstream GP, LLC. Our general partner is not elected by our unitholders and will not be subject to re-election in the future. Summit Investments owns all of the membership interests in our general partner. Our general partner has a board of directors, and our unitholders are not entitled to elect the directors or directly or indirectly to participate in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

Director Independence

Although most companies listed on the NYSE are required to have a majority of independent directors serving on the board of directors of the listed company, the NYSE does not require a listed limited partnership like us to have, and we do not intend to have, a majority of independent directors on the board of directors of our general partner.

Committees of the Board of Directors

The board of directors of our general partner will have an audit committee, or the Audit Committee, and a conflicts committee, or the Conflicts Committee, and may have such other committees as the board of directors shall determine from time to time. Each of the standing committees of the board of directors will have the composition and responsibilities described below.

Audit Committee

Our general partner will have an Audit Committee comprised of at least three directors who meet the independence and experience standards established by the NYSE and the Exchange Act. Our general partner will rely on the phase-in rules of the SEC and the NYSE 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 the registration statement of which this prospectus forms a part, a majority of independent members within 90 days thereafter and all independent members within one year thereafter. The Audit Committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The Audit Committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The Audit Committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the Audit Committee.

Conflicts Committee

At least two members of the board of directors of our general partner will serve on our Conflicts Committee to review specific matters that may involve conflicts of interest in accordance with the terms of our partnership agreement. The Conflicts Committee will determine if the resolution of the conflict of interest is fair and reasonable to us. There is no requirement that our general partner seek the approval of the Conflicts Committee for the resolution of any conflict. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers, employees of any of its affiliates, may not hold any ownership interest in our general partner or us and our

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subsidiaries other than common units and other awards that are granted under our incentive plans in place from time to time, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. Any matters approved by the Conflicts Committee in good faith will be conclusively deemed to be approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. Any unitholder challenging any matter approved by the Conflicts Committee will have the burden of proving that the members of the Conflicts Committee did not subjectively believe that the matter was in the best interests of our partnership. Moreover, any acts taken or omitted to be taken in reliance upon the advice or opinions of experts such as legal counsel, accountants, appraisers, management consultants and investment bankers, where our general partner (or any members of the board of directors of our general partner including any member of the Conflicts Committee) reasonably believes the advice or opinion to be within such person's professional or expert competence, shall be conclusively presumed to have been taken or omitted in good faith.

Directors and Executive Officers

Directors are appointed for a term of one year and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the discretion of the board. The following table shows information for the directors and executive officers of our general partner.

Name		Position with Summit Midstream GP, LLC

Steven J. Newby	39	President, Chief Executive Officer and Director
Matthew S. Harrison	42	Senior Vice President and Chief Financial Officer
Brad N. Graves	45	Senior Vice President, Corporate Development
Rene L. Casadaban	43	Senior Vice President, Engineering, Construction and Operations
Brock M. Degeyter	35	Senior Vice President and General Counsel
Thomas K. Lane	55	Director
Andrew F. Makk	42	Director
Curtis A. Morgan	51	Director
Tyson R. Yates	43	Director

Steven J. Newby has been the President and Chief Executive Officer of our general partner since May 2012. Mr. Newby was a founding member of Summit Midstream Partners, LLC and has been the President and Chief Executive Officer of Summit Midstream Partners, LLC since its formation in September 2009. Mr. Newby's background includes over 15 years of oil and gas experience with a focus on the midstream sector of the energy industry. Mr. Newby was a founding member of SunTrust Bank's Corporate Energy industry specialty group and 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 the energy infrastructure space. Mr. Newby is a graduate of the University of North Carolina at Chapel Hill with a B.S. in Business Administration 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 joining our general partner, Mr. Harrison was the Senior Vice President and Chief Financial Officer of Summit Midstream Partners, LLC since September 2011. Mr. Harrison's background includes over 12 years of energy and finance experience. Mr. Harrison joined Summit Midstream Partners, LLC from Hiland Partners, LP, where he served as Executive Vice President and Chief Financial Officer, Secretary and Director 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

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Mergers & Acquisitions group at A.G. Edwards & Sons, Inc. from July 1999 to October 2007. Mr. Harrison is a Certified Public Accountant and was a Senior Accountant for PricewaterhouseCoopers for five years. Mr. Harrison received an MBA from Northwestern University—Kellogg Graduate School of Management in 1999 and a B.S. in Accounting from the University of Tennessee in 1992.

Brad N. Graves has been the Senior Vice President of Corporate Development of our general partner since May 2012. Prior to joining our general partner, Mr. Graves was the Senior Vice President of Corporate Development of Summit Midstream Partners, LLC since April 2010. He was previously a Partner with Crestwood Midstream Partners, LLC from 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 Products Partners L.P. (NYSE: EPD) from 2004 until August 2006. Prior to 2004, Mr. Graves served in a variety of commercial roles at EPD and GulfTerra Energy Partners, LP (NYSE: GTM), prior to its merger with EPD. In his roles with EPD and GTM, Mr. Graves participated in numerous greenfield projects developed in the Gulf of Mexico. Mr. Graves earned a B.B.A. in Accounting from Texas A&M University in 1989 and an MBA in Marketing and Finance from the University of Saint Thomas in 1994.

Rene L. Casadaban has been the Senior Vice President of Engineering, Construction, and Operations of our general partner since May 2012. Prior to joining our general partner, Mr. Casadaban was the Senior Vice President of Engineering, Construction and Operations of Summit Midstream Partners, LLC from November 2010 to April 2012. 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 Products Partners L.P. from 2006 to 2010 as the Director for Deepwater Development of floating production platforms and offshore pipelines. Mr. Casadaban has also served as an independent consultant to ExxonMobil and GulfTerra for Gulf of Mexico and international pipeline projects. At Land & Marine, Mr. Casadaban was responsible for managing domestic and international pipeline river crossings and beach approaches by horizontal directional drilling. Mr. Casadaban is a graduate of Auburn University 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 joined Summit Midstream Partners, LLC in January 2012 as Senior Vice President and General Counsel. Mr. Degeyter's background includes over ten years of energy, finance and business law experience. Prior to joining our general partner, Mr. Degeyter worked in the corporate legal department for Energy Future Holdings (formerly TXU Corp.) from January 2007 through December 2011 where he served as Director of Corporate Governance and Senior Counsel. Prior to joining Energy Future Holdings, Mr. Degeyter was engaged in private practice with the firm of Correro Fishman Haygood Phelps Walmsley & Casteix LLP from May 2002 through December 2006. Mr. Degeyter is licensed to practice 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.

Thomas K. Lane has served as a director of our general partner since May 2012 and was appointed to the board in connection with his affiliation with Energy Capital Partners, which controls our general partner. Mr. Lane has been a partner of Energy Capital Partners since 2005. Prior to joining Energy Capital Partners, Mr. Lane worked for 17 years in the Investment Banking Division at Goldman Sachs. As a Managing Director at Goldman Sachs, Mr. Lane had senior-level coverage responsibility for electric and gas utilities, independent power companies and merchant energy companies throughout the United States. Mr. Lane received a B.A. in economics from Wheaton College and an MBA from the University of Chicago. Mr. Lane was selected to serve as a director on the board due to his affiliation

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with Energy Capital 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 his affiliation with Energy Capital Partners, which controls our general partner. Mr. Makk has been a Principal at Energy Capital Partners since 2005. Prior to joining Energy Capital Partners, he was a co-founder of a privately held energy company from 2002 to 2005, which built a portfolio of energy projects in Europe on behalf of a private equity fund through the acquisition of existing projects and development of new projects. Prior to 2002, Mr. Makk spent nine years with Enron International in various power and LNG asset development roles and became Head of Asset Development for Enron Europe in London. He received a B.S.M. in Finance from Tulane University and an MBA from the Fuqua School of Business at Duke University. Mr. Makk was selected to serve as a director on the board due to his affiliation with Energy Capital Partners, his knowledge of the energy industry and his financial and business expertise.

Curtis A. Morgan has served as a director of our general partner since May 2012 and was appointed to the board in connection with his affiliation with Energy Capital Partners, which controls our general partner. Mr. Morgan has served as the President and Chief Executive Officer of EquiPower Resources Corp. since May 2010. Prior to joining EquiPower Resources Corp., he served as an Operating Partner of Energy Capital Partners from May 2009 to May 2010. Prior to joining Energy Capital Partners, he served as President and Chief Executive Officer 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 Finance and 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.

Tyson R. Yates has served as a director of our general partner since May 2012 and was appointed to the board in connection with his affiliation with GE Energy Financial Services, Inc. Mr. Yates currently serves as Managing Director of the Midstream portfolio group at GE Energy Financial Services, a position he assumed in March 2007. Over the past 12 years, Mr. Yates has held a variety of positions at GE Energy Financial Services, including Senior Vice President in the Midstream sector investment group. In his current position, Mr. Yates serves on a number of boards that currently include Southern Star Central Corp., a regulated interstate natural gas pipeline system headquartered in Kentucky, SourceGas Holdings Inc., a local gas distribution company headquartered in Colorado, and Phoenix Park Gas Processors Ltd., a natural gas processing plant in Trinidad. Prior to joining GE Energy Financial Services, Mr. Yates held the position of Senior Manager in the Special Acquisition Services and Audit practice at Deloitte & Touche LLP. Mr. Yates has a B.S. in Accounting from the University of Florida and is a Certified Public Accountant. We believe that Mr. Yates's extensive executive and financial experience bring important and necessary skills to the board of directors.

Executive Compensation

The following describes the material components of our compensation policies with respect to the following individuals, who are our general partner's executive officers and referred to as the "named executive officers":

•: Steven J. Newby, President and Chief Executive Officer;
•: Matthew S. Harrison, Senior Vice President and Chief Financial Officer; and
•: Rene L. Casadaban, Senior Vice President, Engineering, Construction and Operations.

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Summary Compensation Table for 2011

The following table sets forth certain information with respect to the compensation paid to our named executive officers for the year ended December 31, 2011.

Name and Principal Position

Steven J. Newby President and Chief Executive Officer	295,500		250,000	—	—	8,865	554,365
Matthew S. Harrison Senior Vice President and Chief Financial Officer	87,176	(5)	235,000	—	911,000	—	1,233,176
Rene L. Casadaban Senior Vice President, Engineering, Construction and Operations	200,000		—	155,000	1,185,826	6,000	1,546,826

(1): Represents discretionary bonuses to Messrs. Newby and Harrison with respect to 2011 company and individual performance (described under "—Elements of Compensation—Annual Incentive Compensation" below), and also includes Mr. Harrison's $25,000 signing bonus.
(2): Represents Mr. Casadaban's incentive bonus earned under our annual incentive bonus program for the year ended December 31, 2011. For a discussion of the determination of these amounts, please read "—Elements of Compensation——Annual Incentive Compensation" below.
(3): Amounts shown in this column for Messrs. Harrison and Casadaban reflect the grant date fair value of the Pre-IPO Equity Awards in accordance with FASB ASC Topic 718. See Note 10 to our Consolidated Financial Statements for the assumptions made in valuing these awards. For additional information regarding the Pre-IPO Equity Awards, please read "—Long-Term Equity-Based Compensation Awards." Mr. Newby's Pre-IPO Equity Awards were granted prior to 2011. For information regarding Mr. Newby's outstanding Pre-IPO Equity Awards, see the Outstanding Equity Awards at December 31, 2011 Table below.
(4): Represents employer contributions under the 401(k) Plan for all named executive officers other than Mr. Harrison, who did not receive any such contributions in 2011.
(5): Mr. Harrison commenced employment with us on September 15, 2011. Amount shown represents the base salary earned by Mr. Harrison for his partial year of employment in 2011.

Narrative Disclosure to Summary Compensation Table

Elements of Compensation

The primary elements of compensation for the named executive officers are base salary, annual incentive compensation 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 retain individuals with superior talent. None of our named executive officers received any base salary adjustments or increases during 2011, other than cost of living increases provided to all of our employees. However, effective March 2012, generally in preparation for this offering, base salary increases were approved for each named executive officer other than

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Mr. Harrison, whose base salary was set in September 2011 upon his commencement of employment with us. The base salaries of our named executive officers before and after the increase, as applicable, are set forth in the following table:

Name and Principal Position

Steven J. Newby President and Chief Executive Officer	297,000	400,000
Matthew S. Harrison Senior Vice President and Chief Financial Officer	295,000	295,000
Rene L. Casadaban Senior Vice President, Engineering, Construction and Operations	200,000	250,000

Annual Incentive Compensation. For 2011, Messrs. Newby and Harrison had target bonuses of $223,500 and $221,250, respectively, or 75% of their base salaries. Our board of directors used its discretion to award both executives bonuses slightly in excess of their targets because, although we underperformed on our Adjusted EBITDA targets, we successfully completed our acquisition of the Grand River system under their leadership. Pursuant to Mr. Harrison's employment agreement, his bonus was not prorated, despite his September hire date.

Mr. Casadaban's target incentive compensation was 75% of his base salary, or $150,000. Quantitative factors determined 70% of Mr. Casadaban's incentive compensation and qualitative factors determined 30%. Quantitative factors considered in determining the bonus included achievement of certain Adjusted EBITDA thresholds, construction goals and operational and safety goals. Although we underperformed on our Adjusted EBITDA targets, we achieved near target on our construction goals and significantly above target on our operational goals. As a result, Mr. Casadaban was awarded $79,800 or 76% of target for the portion of his bonus based on quantitative factors, and $75,200 or 167% of target for the portion of his bonus based on qualitative factors, primarily due to his significant contributions to the closing of the acquisition of the Grand River system. In total, Mr. Casadaban was awarded approximately 103% of his target incentive compensation for 2011.

Long-Term Equity-Based Compensation Awards. The named executive officers were each granted equity-based compensation awards in the form of interests ("upstairs profits interests") in a collective partnership vehicle, referred to in this prospectus as Summit Management, through which our named executive officers indirectly hold Class B percentage interests in Summit Investments ("downstairs profits interests"). The downstairs profits interests represent indirect interests in Summit Investments' future profits, and allow Summit Management to share in distributions by Summit Investments only after Summit Investments' Class A Members have received distributions in an amount equal to the sum of the fair market value of the downstairs profits interests at the time of grant plus any capital contributions made subsequent to the date of grant. The upstairs profits interests entitle the named executive officers to receive from Summit Management the proceeds of any distributions received by Summit Management from Summit Investments in respect of the corresponding downstairs profits interests, subject to the terms set forth in the partnership agreement of Summit Management. The upstairs profits interests are referred to in this prospectus as the Pre-IPO Equity Awards.

The Pre-IPO Equity Awards were granted subject to a five-year time-based vesting schedule, subject to the named executive officer's continued employment through the applicable vesting date. The Pre-IPO Equity Awards are eligible for an additional one year of vesting in the event the named executive officer's employment is involuntarily terminated by the applicable employer without cause, or is terminated due to the named executive officer's death or disability, or, in the case of Mr. Newby, is

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terminated by him due to his resignation with good reason (as defined in the employment agreements, described below). The Pre-IPO Equity Awards are eligible for full 100% accelerated vesting if the named executive officer's employment is involuntarily terminated without cause or, in the case of Mr. Newby, is terminated by the named executive officer due to his resignation with good reason, within the 12 months after a change in control of Summit Investments. In the event of a named executive officer's termination of employment for any other reason, the named executive officer's Pre-IPO Equity Awards will be forfeited.

Pursuant to the applicable partnership agreements, the vested downstairs profits interests may be repurchased by the applicable employer or Energy Capital Partners in certain circumstances. In the event of the termination of a named executive officer's employment due to death, disability, termination by the applicable employer without cause or, in the case of Mr. Newby, resignation with good reason or non-extension of the term of the employment agreement, the repurchase price will be equal to the value of the downstairs profits interests in a hypothetical liquidation of the applicable employer pursuant to the rights and preferences set forth in the partnership agreement, assuming all assets were sold for their fair market value. In the event of termination for cause, resignation (in the case of Mr. Newby, without good reason) or a purported transfer by the named executive officer or the management company in violation of the partnership agreement, the repurchase price will equal $0. In the event of a repurchase of the downstairs profits interests, the corresponding upstairs profits interests will be repurchased from the named executive officer by Summit Management for the same repurchase price.

Going forward, we expect that equity-based incentive awards will be made more regularly and that equity-based awards will become more prominent in our annual compensation decision-making process. In anticipation of this offering, we intend to adopt a new long-term equity incentive plan, which is discussed in more detail under "2012 Long-Term Incentive Plan" below.

Retirement, Health and Welfare and Additional Benefits. The named executive officers are eligible to participate in such employee benefit plans and programs as we may from time to time offer to our employees, subject to the terms and eligibility requirements of those plans. The named executive officers are eligible to participate in a tax-qualified 401(k) defined contribution plan to the same extent as all of our other employees. In 2011, we made a fully vested contribution on behalf of each of the 401(k) plan's participants equal to 3% of such participant's salary for the year.

Outstanding Equity Awards at December 31, 2011

The following table provides information regarding the Pre-IPO Equity Awards held by the named executive officers as of December 31, 2011.



Steven J. Newby	May 1, 2010	1.05	%(1)	3,845,947
	March 1, 2011	.056	%(1)	195,861
Matthew S. Harrison	September 15, 2012	.85	%(1)	1,346,400
Rene L. Casadaban	October 1, 2011	.52	%(1)	1,177,008

(1): Represents the upstairs profits interests in Summit Management attributable to the unvested Pre-IPO Equity Awards held by each of our named executive officers. The Pre-IPO Equity Awards vest in five equal annual installments beginning on the first anniversary of the vesting commencement date.
(2): There is no public market for the Pre-IPO Equity Awards. We valued the Pre-IPO Equity Awards with the assistance of a third-party valuation expert for purposes of this disclosure. The amount

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reported above under the heading "Market Value of Units That Have Not Vested" reflects the fair market value of our Pre-IPO Equity Awards as of December 31, 2011.

Employment and Severance Arrangements

We have entered into employment agreements with Steven J. Newby (dated September 3, 2009), and Matthew S. Harrison (dated September 15, 2011). Rene Casadaban is not a party to an employment agreement.

The current term of Mr. Newby's employment agreement expires on August 31, 2012. Mr. Harrison's employment agreement has an initial term of two years, and is then automatically extended for successive one-year periods, unless either party gives notice of non-extension to the other no later than 90 days prior to the expiration of the then-applicable term. Each employment agreement provided for the named executive officer's initial base salary and a performance-based bonus ranging from 0% to 150% of base salary, with a target of 75% of base salary. Mr. Harrison's employment agreement also provides for a $25,000 cash signing bonus, reimbursement for up to $60,000 in relocation expenses incurred in relocating to Atlanta, Georgia, and reimbursement for tax preparation expenses in the amount of $10,000 per year. No such reimbursements were yet paid to Mr. Harrison in 2011.

Each employment agreement provides for a cash severance payment upon a termination by us without cause or by the named executive officer for good reason, which is defined generally as the named executive 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 named executive officer's base compensation, (iii) a material change in the geographic location at which the named executive 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 us. Each employment agreement provides that the named executive officer's severance payment will be equal to the sum of his annual base salary and the annual bonus payable in respect of 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 of termination and ending on the later of (a) the last day of the then-applicable term of the employment agreement and (b) the first anniversary of the date of termination (the "severance period") and the denominator of which is 365. The severance payment is payable in equal installments during the severance period.

Following any termination of employment other than one resulting from non-extension of the term, each of Messrs. Newby and Harrison will be subject to a post-termination non-competition covenant through the severance period. Following any termination of employment, each of Messrs. Newby and Harrison will be subject to a one-year post-termination non-solicitation covenant.

In the case of Messrs. Newby and Harrison, if the named executive officer's employment is terminated due to non-extension of the term by us or by the named executive officer, we may choose to subject him to a non-competition covenant for up to one year post-termination. If we exercise this "noncompete option", then the named executive officer will be entitled to a severance 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 the restricted period (as elected by us) and the denominator of which is 365. In this case, the severance payment will be payable in equal installments over the restricted period.

Any severance payment payable to a named executive officer pursuant to his employment agreement will be subject to his execution and non-revocation of a release of claims in favor of us.

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As described above, the Pre-IPO Equity Awards provide for certain acceleration in the event of certain terminations of employment, including certain terminations in connection with a change in control of Summit Investments.

2012 Long-Term Incentive Plan

Prior to the consummation of this offering, our general partner intends to adopt a 2012 Long-Term Incentive Plan, or LTIP, pursuant to which our, our subsidiaries' and our general partner's eligible officers (including the named executive officers), employees, consultants and directors will be eligible to receive awards with respect to our equity interests, thereby linking the recipients' compensation directly to our performance. The description of the LTIP set forth below is a summary of the anticipated material features of the LTIP. This summary, however, does not purport to be a complete description of all of the anticipated provisions of the LTIP. In addition, our general partner is still in the process of implementing the LTIP and, accordingly, this summary is subject to change prior to the effectiveness of the registration statement of which this prospectus is a part.

The LTIP will provide 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 and other unit-based awards. Subject to adjustment in the event of certain transactions or changes in capitalization, an aggregate of common units may be delivered pursuant to awards under the LTIP. Units that are cancelled or forfeited will be available for delivery pursuant to other awards. We expect that the LTIP will be administered by our general partner's board of directors, though such administration function may be delegated to a committee (including the compensation committee) that may be appointed by the board to administer the LTIP. The LTIP will be designed to promote our interests, as well as the interests of our unitholders, by rewarding the officers, employees, consultants and directors of us, our subsidiaries and our general partner for delivering desired performance results, as well as by strengthening our and our general partner's ability to attract, retain and motivate qualified individuals to serve as directors, consultants and employees.

Restricted Units and Phantom Units

A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee 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 the discretion of the administrator, cash equal to the fair market value of a common unit. The administrator of the LTIP may make grants of restricted and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the administrator may determine are appropriate, including the period over which restricted or phantom units will vest. The administrator of the LTIP may, in its discretion, base vesting on the grantee's completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change 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.

Distribution Equivalent Rights

The administrator of the LTIP, in its discretion, may also grant distribution equivalent rights, either as standalone awards or in tandem with other awards. Distribution equivalent rights are rights to receive an amount in cash, restricted units or phantom units equal to all or a portion of the cash distributions made on units during the period an award remains outstanding.

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Unit Options and Unit Appreciation Rights

The LTIP may also permit the grant of options covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the administrator of the LTIP may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price equal to at least the fair market value of a common unit on the date of grant.

Unit Awards

Awards covering common units may be granted under the LTIP with such terms and conditions, including restrictions on transferability, as the administrator of the LTIP may establish.

Profits Interest Units

Awards granted to grantees who are partners, or granted to grantees in anticipation of the grantee becoming a partner or granted as otherwise determined by the administrator, may consist of profits interest units. The administrator will determine the applicable vesting dates, conditions to vesting and restrictions on transferability and any other restrictions for profits interest awards.

Other Unit-Based Awards

The LTIP may also permit the grant of "other unit-based awards," which are awards that, in whole or in part, are valued or based on or related to the value of a common unit. The vesting of an other unit-based award may be based on a participant's continued service, the achievement of performance criteria or other measures. On vesting or on a deferred basis upon specified future dates or events, an other unit-based award may be paid in cash and/or in units (including restricted units), or any combination thereof as the administrator of the LTIP may determine.

Source of Common Units; Cost

Common units to be delivered with respect to awards may be newly-issued units, common units acquired by us or our general partner in the open market, common units already owned by our general partner or us, common units acquired by 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 any time with respect to the common units for which a grant has not previously been made. The LTIP will automatically terminate on the 10th anniversary of the date it was initially adopted by our general partner. The administrator of the LTIP will also have the right to alter or amend the 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 any outstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information regarding the beneficial ownership of units following the closing of this offering and the related transactions by:

•: each person who is known to us to beneficially own 5% or more of such units to be outstanding;
•: 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 the case may be.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a "beneficial owner" of a security if that person has or shares "voting power," which includes the power to vote or to direct the voting of such security, or "investment power," which includes the power to dispose of or to direct the disposition of such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units subject to options or warrants held by that person that are currently exercisable or exercisable within 60 days of , 2012, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

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The percentage of units beneficially owned is based on a total of common units and subordinated units outstanding immediately following this offering.

Name Of Beneficial Owner

Summit Midstream Partners LLC(1) (2)	%	%	%
Energy Capital Partners II, LP(3) (5)	%	%	%
Energy Capital Partners II-A, LP(3) (5)	%	%	%
Energy Capital Partners II-B IP, LP(3) (5)	%	%	%
Energy Capital Partners II-C (Summit IP), LP(3) (5)	%	%	%
Energy Capital Partners II (Summit Co-Invest), LP(3) (5)	%	%	%
EFS-S LLC(6) (7)	%	%	%
Steven J. Newby(1)	%	%	%
Matthew S. Harrison(1)	%	%	%
Brad N. Graves(1)	%	%	%
Rene L. Casadaban(1)	%	%	%
Brock M. Degeyter(1)	%	%	%
Thomas K. Lane(3)	%	%	%
Andrew F. Makk(3)	%	%	%
Curtis A. Morgan(4)	%	%	%
Tyson R. Yates(6)	%	%	%
All directors and executive officers as a group (consisting of persons)	%	%	%

(1): The address for this person or entity is 2100 McKinney Avenue, Suite 1250, Dallas, Texas 75201.
(2): Steven J. Newby, Matthew S. Harrison, Brad N. Graves, Rene L. Casadaban and Brock M. Degeyter, each of whom are executive officers of our general partner, own Class B profits interests of Summit Midstream Management, LLC.
(3): The address for this person or entity is 51 John F. Kennedy Parkway, Suite 200, Short Hills, New Jersey 07078.
(4): The address for Mr. Morgan is 100 Constitution Plaza, 10th Floor, Hartford, Connecticut 06103.
(5): Energy Capital Partners II, LP and the other limited partnerships listed in the table above (collectively, the "ECP Funds") are members of Summit Midstream Partners, LLC and may therefore be deemed to beneficially own the common units and subordinated units held by Summit Midstream Partners, LLC. As holders of an 88.75% ownership interest of Summit Midstream Partners, LLC, the ECP Funds are entitled to elect four directors of Summit Midstream Partners, LLC. Thomas Lane and Andrew Makk are each a director of our general partner. In addition, Mr. Lane is a partner, and Mr. Makk is a principal at Energy Capital

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Partners II, LLC, the managing member of the general partner of the ECP Funds. They disclaim beneficial interest in our common and subordinated units except to their pecuniary interest therein.

(6): The address for this person or entity is 800 Long Ridge Road, Stamford, Connecticut 06927.
(7): EFS-S LLC, a wholly owned subsidiary of GE Energy Financial Services, Inc., is a member of Summit Midstream Partners, LLC and may therefore be deemed to beneficially own the common units and subordinated units held by Summit Midstream Partners, LLC. As holders of an 11.25% ownership interest of Summit Midstream Partners, LLC, EFS-S LLC is entitled to elect one director of Summit Midstream Partners, LLC. Tyson R. Yates, a director of our general partner, is a Vice President at EFS-S LLC. He disclaims beneficial interest in our common and subordinated units except to his pecuniary interest therein.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Immediately following the closing of this offering, Summit Investments will own common units and subordinated units, representing a combined % limited partner interest in us (or common units and subordinated units, representing a combined % limited partner interest in us, if the underwriters exercise their option to purchase additional common units in full). In addition, Summit Investments will own and control our general partner, which will own a 2.0% general partner interest in us and all of our incentive distribution rights.

Distributions and Payments to our General Partner and its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and any liquidation of Summit Midstream Partners, LP These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations.

Formation Stage

The consideration received by our general partner and its affiliates prior to or in connection with this offering

•

common units;

•

subordinated units;

•

all of our incentive distribution rights;

•

2.0% general partner interest;

•

a $ cash payment from the proceeds of the offering; and

•

the right to have up to common units redeemed with the proceeds of any exercise of the underwriters' option to purchase additional common units.

Operational Stage


Distributions of available cash to our general partner and its affiliates		We will initially make cash distributions 98.0% to our unitholders pro rata, including Summit Investments, as the holder of an aggregate of 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 by our general partner will entitle our general partner to increasing percentages of the distributions, up to 48.0% of the distributions above the highest target distribution level.
		Assuming we have sufficient cash available to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $ million on its 2.0% general partner interest and Summit Investments would receive an annual distribution of approximately $ million on its common units and subordinated units.

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Payments to our general partner and its affiliates		Our general partner will not receive a management fee or other compensation for its management of us. However, we will reimburse our general partner and its affiliates for all expenses incurred on our behalf. Under our partnership agreement, we will reimburse our general partner and its affiliates for certain expenses incurred on our behalf, including, without limitation, salary, bonus, incentive compensation and other amounts paid to our general partner's employees and executive officers who perform services necessary to run our business, which we project to be approximately $19.5 million for the twelve months ending June 30, 2013. In addition, we estimate that we will reimburse our general partner for approximately $1.0 million annually 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 officer liability insurance. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.
Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read "The Partnership Agreement—Withdrawal or Removal of Our General Partner."

Liquidation Stage


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

Agreements with Affiliates

We have various agreements with certain of our affiliates, as described below. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm's-length negotiations.

Promissory Notes

In conjunction with the purchase of the Grand River system, Summit Investments executed promissory notes, on an unsecured basis, with our sponsors. The notes totaled $200 million and had an 8% interest rate and a maturity date of October 27, 2013. The outstanding balance under the notes was paid in full on July 2, 2012.

EquiPower Electricity Management Services Agreement

In December 2011, we entered into a consulting arrangement with EquiPower Resources Corp., or EquiPower, an affiliate of Energy Capital Partners, whereby EquiPower assists us with managing our electricity price risk. During the year ended December 31, 2011, we paid EquiPower $11,000 for such

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services. Curtis A. Morgan, a member of the board of directors of our general partner, is the President and Chief Executive Officer of EquiPower.

Procedures for Review, Approval and Ratification of Related-Person Transactions

The board of directors of our general partner will adopt a code of business conduct and ethics in connection with the closing of this offering that will provide that the board of directors of our general partner or its authorized committee will periodically review all related-person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related-person transaction and determines not to so ratify, the code of business conduct and ethics will provide that our management will make all reasonable efforts to cancel or annul the transaction.

The code of business conduct and ethics will provide that, in determining whether to recommend the initial approval or ratification of a related-person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on director independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediately family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.

The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result the transactions described above were not reviewed under such policy.

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CONFLICTS OF INTEREST AND DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Summit Investments), on the one hand, and us and our unaffiliated limited partners, on the other hand. The directors and executive officers of our general partner have duties to manage our general partner in a manner they subjectively believe is in the best interests of its owners. At the same time, the directors and executive officers of our general partner have a duty to manage us in a manner they subjectively believe is in our best interests.

The Delaware Revised Uniform Limited Partnership Act, which we refer to as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to the limited partners and the partnership. As permitted by the Delaware Act, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner to us and our unitholders with contractual standards governing the duties of the general partner to us and our unitholders and the methods for resolving conflicts of interest. Our partnership agreement also specifically defines the duties our general partner owes to us and our unitholders with respect to actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other, our general partner will resolve that conflict. Our general partner may seek the approval of such resolution from the Conflicts Committee. There is no requirement that our general partner seek the approval of the Conflicts Committee for the resolution of any conflict, and, under our partnership agreement, our general partner may decide to seek such approval or resolve a conflict of interest in any other way permitted by our partnership agreement, as described below, in its sole discretion. Our general partner will decide whether to refer the matter to the Conflicts Committee on a case-by-case basis. An independent third party is not required to evaluate the fairness of the resolution.

Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:

•: approved by the Conflicts Committee;
•: approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;
•: determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
•: determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

If the resolution or course of action taken with respect to the conflict of interest satisfies any of the standards set forth in the first, third or fourth bullet points above, then such resolution or course of action will be deemed to be approved by all of our unitholders and, in the case of all four bullet points above, will not constitute a breach of our partnership agreement or of any duties our general partner may owe us or our unitholders.

Our general partner may, but is not required to, seek approval from the Conflicts Committee of a resolution of a conflict of interest with our general partner or affiliates. Any matters approved by the Conflicts Committee will be presumed to have been approved in good faith. If our general partner does

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not seek approval from the Conflicts Committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third or fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith and, in each case, in any proceeding brought by or on behalf of any limited partner or us challenging such approval, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the Conflicts Committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to subjectively believe that he or she is acting in our best interests or meets the specified standard, for example, a transaction on terms no less favorable to the partnership than those generally being provided to or available from unrelated third parties. Please read "Management—Committees of the Board of Directors—Conflicts Committee" for information about the Conflicts Committee.

Conflicts of interest could arise in the situations described below, among others.

Affiliates of our general partner may compete with us. Neither our partnership agreement nor any other agreement requires Summit Investments to pursue a business strategy that favors us or utilizes our assets or dictates what markets to pursue or grow.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner (or as general partner of another company of which we are a partner or member) or those activities incidental to its ownership of interests in us. However, affiliates of our general partner, including Energy Capital Partners and GE Energy Financial Services, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Additionally, Energy Capital Partners and GE Energy Financial Services, through their investment funds and managed accounts, make investments and purchase entities in various areas of the energy sector, including the midstream natural gas industry. These investments and acquisitions may include entities or assets that we would have been interested in acquiring.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner or any of its affiliates, including its executive officers, directors, Energy Capital Partners and GE Energy Financial Services. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Therefore, Energy Capital Partners and GE Energy Financial Services may compete with us for investment opportunities and may own an interest in entities that compete with us.

Our general partner is allowed to take into account the interests of parties other than us, such as Energy Capital Partners, in resolving conflicts.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner or otherwise, free of any duty or obligation whatsoever to us and our unitholders, including any duty to act in the best interests of us or our unitholders, other than the implied contractual duty of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This entitles our general partner to consider only the interests and

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factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of our general partner's limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership.

Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner to us and our unitholders with contractual standards governing its duties and limits our general partner's liabilities and the rights of our unitholders with respect to actions that might otherwise constitute breaches of fiduciary duty under applicable Delaware law.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of our general partner's fiduciary duty. For example, our partnership agreement:

•: permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any unitholder;
•: provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as such decisions are made in good faith, which means the subjective belief that the decision is in our best interests;
•: provides generally that affiliated transactions and resolutions of conflicts of interest not approved by the Conflicts Committee and not involving a vote of unitholders must either be (1) on terms no less favorable to us than those generally being provided to or available from unrelated third parties or (2) "fair and reasonable" to us, as determined by our general partner in good faith,provided that, in determining whether a transaction or resolution is "fair and reasonable," our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us, and in any proceeding brought by or on behalf of any limited partner or us challenging such decision, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and
•: provides that our general partner and its executive officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its executive officers or directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that their conduct was criminal.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought Conflicts Committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:

•: the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;

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•: the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;
•: the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;
•: the negotiation, execution and performance of any contracts, conveyances or other instruments;
•: the distribution of our cash;
•: the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;
•: the maintenance of insurance for our benefit and the benefit of our partners;
•: the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnership, joint venture, corporation, limited liability company or other entity;
•: the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity, otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense, the settlement of claims and litigation;
•: the indemnification of any person against liabilities and contingencies to the extent permitted by law;
•: the making of tax, regulatory and other filings, or the rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and
•: the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Our partnership agreement provides that our general partner must act in "good faith" when making decisions on our behalf, and our partnership agreement further provides that in order for a determination to be made in "good faith," our general partner must have a subjective belief that the determination is in our best interests. Please read "The Partnership Agreement—Voting Rights" for information regarding matters that require unitholder approval.

Actions taken by our general partner may affect the amount of cash available for distribution to unitholders or accelerate the right to convert subordinated units.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

•: the amount and timing of asset purchases and sales;
•: cash expenditures and the amount of estimated reserve replacement expenditures;
•: borrowings;
•: the issuance of additional units; and
•: the creation, reduction or increase of reserves in any quarter.

Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert into common units.

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In addition, our general partner may use an amount, initially equal to $ million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and may facilitate the conversion of subordinated units into common units. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions."

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

•: enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or
•: hastening the expiration of the subordination period.

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordination Period."

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, or our operating company and its operating subsidiaries.

We will reimburse our general partner and its affiliates for expenses.

We will reimburse our general partner and its affiliates for costs incurred in managing and operating us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith, and it will charge on a fully allocated cost basis for services provided to us. The fully allocated basis charged by our general partner does not include a profit component. Please read "Certain Relationships and Related Party Transactions."

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm's-length negotiations.

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts, and arrangements between us and our general partner and its affiliates are or will be the result of arm's-length negotiations. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the closing of this offering will not be required to be negotiated on an arm's-length basis, although, in some circumstances, our general partner may determine that the Conflicts Committee may make a determination on our behalf with respect to such arrangements.

Our general partner will determine, in good faith, the terms of any of these transactions entered into after the close of this offering.

Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically for such use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

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

Our general partner intends to limit its liability under contractual arrangements so that counterparties to such agreements have recourse only against our assets and not against our general partner or its assets or any affiliate of our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner's duties, even if we could have obtained terms that are more favorable without the limitation on liability.

Common units are subject to our general partner's limited call right.

Our general partner may exercise its right to call and purchase common units, as provided in our partnership agreement, or may assign this right to one of its affiliates or to us free of any liability or obligation to us or our unitholders. As a result, a common unitholder may have to sell his common units at an undesirable time or price. Please read "The Partnership Agreement—Limited Call Right."

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the Conflicts Committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the minimum quarterly distribution and the target distribution levels related to our general partner's incentive distribution rights without the approval of the Conflicts Committee or our unitholders. This election may result in lower distributions to our public common unitholders in certain situations.

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters and the amount of each such distribution did not exceed the adjusted operating surplus for such quarter, to reset the initial minimum quarterly distribution and target distribution levels at higher levels based on the average cash distribution amount per common unit for the two fiscal quarters prior to the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the "reset minimum quarterly distribution"), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise

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this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels related to our general partner's incentive distribution rights. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Distribution of Available Cash—General Partner Interest and Incentive Distribution Rights."

Duties of Our General Partner

The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, modify or eliminate, except for the contractual covenant of good faith and fair dealing, the fiduciary duties owed by the general partner to limited partners and the partnership.

Our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner to us and our unitholders with contractual standards governing the duties of the general partner to us and our unitholders and the methods for resolving conflicts of interest. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has a duty to manage our general partner in a manner it believes is in the best interests of its owners. Without these provisions, our general partner's ability to make decisions involving conflicts of interest would be restricted. The replacement of fiduciary standards enable our general partner to take into consideration the interests of all parties involved. These provisions also strengthen the ability of our general partner to attract and retain experienced and capable directors. These provisions may be detrimental to our unitholders, however, because they restrict the rights and remedies that would otherwise be available to unitholders for actions that might otherwise constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of:

•: the fiduciary duties imposed on general partners of a limited partnership by the Delaware Act in the absence of partnership agreement provisions to the contrary;
•: the contractual duties of our general partner contained in our partnership agreement that replace the fiduciary duties that would otherwise be imposed by Delaware law on our general partner; and
•: certain rights and remedies of limited partners contained in the Delaware Act.

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State law fiduciary duty standards		Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to use that amount of care that an ordinarily careful and prudent person would use in similar circumstances and to consider all material information reasonably available in making business decisions. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present unless such transaction were entirely fair to the partnership.
Partnership agreement modified standards		Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in "good faith," meaning that it subjectively believed that the decision was in our best interests, and will not be subject to any other standard under applicable law, other than the implied contractual covenant of good faith and fair dealing. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any duty or obligation to us or our unitholders whatsoever other than the implied contractual covenant of good faith and fair dealing. These standards reduce the obligations to which our general partner would otherwise be held under applicable Delaware law.
		Special Provisions Regarding Affiliated Transactions. Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest that are not approved by a vote of unitholders or by the Conflicts Committee must be:
		• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
		• fair and reasonable to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).

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		If our general partner does not seek approval from the Conflicts Committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such approval, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Any matter approved by the Conflicts Committee will be presumed to have been approved in good faith. These standards reduce the obligations to which our general partner would otherwise be held. In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner, its affiliates and their officers and directors will not be liable for monetary damages to us or our limited partners for losses sustained or liabilities incurred as a result of any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that such person acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.
Rights and remedies of unitholders		The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has wrongfully refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These legal actions include actions against a general partner for breach of fiduciary duty, if any, or the partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

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By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful. We also must provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act of 1933, or the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and therefore unenforceable. Please read "The Partnership Agreement—Indemnification."

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DESCRIPTION OF OUR COMMON UNITS

The Units

The common units represent limited partner interests in us. The holders of common units, along with the holders of subordinated units, are entitled to participate in partnership distributions and are entitled to exercise the rights and privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and "Our Cash Distribution Policy and Restrictions on Distributions." For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read "The Partnership Agreement."

Transfer Agent and Registrar

Duties

will serve as the registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by our unitholders:

•: surety bond premiums to replace lost or stolen certificates, or to cover taxes and other governmental charges in connection therewith;
•: special charges for services requested by a holder of a common unit; and
•: other similar fees or charges.

There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their respective stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

•: automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement;
•: represents and warrants that the transferee has the right, power, authority and capacity to enter into our partnership agreement; and
•: gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

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Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder's rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing the transfer of securities.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

•: with regard to distributions of available cash, please read "Provisions of Our Partnership Agreement Relating to Cash Distributions";
•: with regard to the duties of our general partner, please read "Conflicts of Interest and Duties";
•: with regard to the transfer of common units, please read "Description of Our Common Units—Transfer of Common Units"; and
•: with regard to allocations of taxable income and taxable loss, please read "Material Federal Income Tax Consequences."

Organization and Duration

We were organized in Delaware in May 2012 and have a perpetual existence.

Purpose

Our purpose under our partnership agreement is limited to any business activities that are approved by our general partner and in any event that lawfully may be conducted by a limited partnership organized under Delaware law;provided that our general partner may not cause us to engage, directly or indirectly, in any business activity that our general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the power to cause us, our operating company and its subsidiaries to engage in activities other than the business of gathering, compressing and transporting natural gas, our general partner has no current plans to do so and may decline to do so free of any duty or obligation whatsoever to us or our unitholders. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Cash Distributions

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to our general partner in respect of its general partner interest and its incentive distribution rights. For a description of these cash distribution provisions, please read "Provisions of Our Partnership Agreement Relating to Cash Distributions."

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under "—Limited Liability."

For a discussion of our general partner's right to contribute capital to maintain its 2.0% general partner interest if we issue additional units, please read "—Issuance of Additional Securities."

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Voting Rights

The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that require the approval of a "unit majority" require:

•: during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our general partner and its affiliates, and a majority of the outstanding subordinated units, voting as separate classes; and
•: after the subordination period, the approval of a majority of the outstanding common units.

By virtue of the exclusion of those common units held by our general partner and its affiliates from the required vote, and by their ownership of all of the subordinated units, during the subordination period our general partner and its affiliates do not have the ability to ensure passage of, but do have the ability to ensure defeat of, any amendment that requires a unit majority.

In voting their common and subordinated units, our general partner and its affiliates will have no duty or obligation whatsoever to us or our unitholders, including any duty to act in the best interests of us or our unitholders.


Issuance of additional units		No approval right.
Amendment of our partnership agreement		Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read "—Amendment of Our Partnership Agreement."
Merger of our partnership or the sale of all or substantially all of our assets		Unit majority in certain circumstances. Please read "—Merger, Sale or Other Disposition of Assets."
Dissolution of our partnership		Unit majority. Please read "—Termination and Dissolution."
Continuation of our business upon dissolution		Unit majority. Please read "—Termination and Dissolution."
Withdrawal of our general partner		Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to in a manner that would cause a dissolution of our partnership. Please read "—Withdrawal or Removal of Our General Partner."
Removal of our general partner		Not less than 66²/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read "—Withdrawal or Removal of Our General Partner."

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Transfer of our general partner interest		Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to . Please read "—Transfer of General Partner Interest."
Transfer of incentive distribution rights		Except for transfers to an affiliate or to another person as part of our general partner's merger or consolidation, sale of all or substantially all of its assets or the sale of all of the ownership interests in such holder, the approval of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required in most circumstances for a transfer of the incentive distribution rights to a third party prior to . Please read "—Transfer of Incentive Distribution Rights."
Transfer of ownership interests in our general partner		No approval required at any time. Please read "—Transfer of Ownership Interests in Our General Partner."

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that it otherwise acts in conformity with the provisions of our partnership agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right of, or exercise of the right by, the limited partners as a group:

•: to remove or replace our general partner;
•: to approve some amendments to our partnership agreement; or
•: to take other action under our partnership agreement;

constituted "participation in the control" of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us who reasonably believe that a limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for such a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership, except

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that the fair value of property that is subject to a liability for which the recourse of creditors is limited is included in the assets of the limited partnership only to the extent that the fair value of that property exceeds that liability. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of its assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to it at the time it became a limited partner and that could not be ascertained from the partnership agreement.

Our subsidiaries conduct business primarily in three states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a member of our operating company may require compliance with legal requirements in the jurisdictions in which our operating company conducts business, including qualifying our subsidiaries to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted "participation in the control" of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of our limited partners.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have rights to distributions or special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity securities, which may effectively rank senior to the common units.

Upon issuance of additional partnership securities (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2.0% general partner

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interest in us. Our general partner's 2.0% interest in us will be reduced if we issue additional units in the future (other than in those circumstances described above) and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership securities.

Amendment of Our Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or our unitholders, including any duty to act in the best interests of our partnership or our unitholders. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner must seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:

•: enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or
•: enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.

The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90.0% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Upon the closing of this offering, affiliates of our general partner will own approximately % of the outstanding common and subordinated units.

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

•: a change in our name, the location of our principal place of business, our registered agent or our registered office;
•: the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;
•: a change that our general partner determines to be necessary or appropriate for us to qualify or to continue our qualification as a limited partnership or a partnership in which the limited

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partners have limited liability under the laws of any state or to ensure that neither we, our operating company, nor its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

•: a change in our fiscal year or taxable year and related changes;
•: an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents, or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940 or "plan asset" regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;
•: an amendment that our general partner determines to be necessary or appropriate in connection with the authorization of issuance of additional partnership securities or rights to acquire partnership securities;
•: any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;
•: an amendment effected, necessitated, or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;
•: any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership, joint venture, limited liability company or other entity, as otherwise permitted by our partnership agreement;
•: mergers with, conveyances to or conversions into another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the merger, conveyance or conversion other than those it receives by way of the merger, conveyance or conversion; or
•: any other amendments substantially similar to any of the matters described above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:

•: do not adversely affect in any material respect the limited partners considered as a whole or any particular class of partnership interests as compared to other classes of partnership interests;
•: are necessary or appropriate to satisfy any requirements, conditions, or guidelines contained in any opinion, directive, order, ruling, or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;
•: are necessary or appropriate to facilitate the trading of units or to comply with any rule, regulation, guideline, or requirement of any securities exchange on which the units are or will be listed for trading;
•: are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or
•: are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

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Opinion of Counsel and Limited Partner Approval

Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments described above under "—No Unitholder Approval." No other amendments to our partnership agreement will become effective without the approval of holders of at least 90.0% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be reduced. Any amendment that would increase the percentage of units required to remove our general partner must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than 90% of outstanding units. Any amendment that would increase the percentage of units required to call a meeting of unitholders must be approved by the affirmative vote of unitholders whose aggregate outstanding units constitute at least a majority of the outstanding units.

Merger, Sale or Other Disposition of Assets

A merger or consolidation of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger or consolidation and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of our partnership or our unitholders.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our and our subsidiaries' assets in a single transaction or a series of related transactions, including by way of merger, consolidation, other combination or sale of ownership interests of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate, or grant a security interest in all or substantially all of our and our subsidiaries' assets without that approval. Our general partner may also sell all or substantially all of our and our subsidiaries' assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of the limited partners), each of our units will be an identical unit of our partnership following the transaction and the partnership securities to be issued do not exceed 20.0% of our outstanding partnership securities immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed limited liability entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters' rights of appraisal under our partnership

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agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:

•: the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following the approval and admission of a successor general partner;
•: the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;
•: the entry of a decree of judicial dissolution of our partnership; or
•: there being no limited partners, unless we are continued without dissolution in accordance with the Delaware Act.

Upon a dissolution under the first clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement and appoint as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

•: the action would not result in the loss of limited liability of any limited partner; and
•: neither we nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in "Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Cash Upon Liquidation." The liquidator may defer liquidation or distribution of our assets for a reasonable period of time if it determines that an immediate sale or distribution would be impractical or would cause undue loss to our partners. The liquidator may distribute our assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to , 2022 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after , 2022 our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving at least 90 days' written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days' notice to the limited partners if at least 50.0% of the outstanding common units are held or controlled by one person and its affiliates, other than our general partner and its affiliates. In addition, our partnership agreement

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permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read "—Transfer of General Partner Interest" and "—Transfer of Incentive Distribution Rights."

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period of time after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read "—Termination and Dissolution."

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66²/3% of all outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, and a majority of the outstanding subordinated units, voting as a single class. The ownership of more than 33¹/3% of the outstanding units by our general partner and its affiliates gives them the ability to prevent our general partner's removal. At the closing of this offering, affiliates of our general partner will own % of the outstanding common and subordinated units.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist:

•: the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis, provided (i) neither such person nor any of its affiliates voted any of its units in favor of the removal and (ii) such person is not an affiliate of the successor general partner; and
•: if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end.

In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for their fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner's general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

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In addition, we will be required to reimburse the departing general partner for all amounts due to it, including, without limitation, all employee-related liabilities, including severance liabilities, incurred in connection with the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interest

Except for transfer by our general partner of all, but not less than all, of its general partner interest to:

•: an affiliate of our general partner (other than an individual); or
•: another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity, our general partner may not transfer all or any of its general partner interest to another person prior to , 2022 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may, at any time, transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in Our General Partner

At any time, the owners of our general partner may sell or transfer all or part of their ownership interests in our general partner to an affiliate or a third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

Our general partner or its affiliates or a subsequent holder may transfer any or all of its incentive distribution rights without unitholder approval.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change our management. Please read "—Withdrawal or Removal of Our General Partner" for a discussion of certain consequences of the removal of our general partner. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20.0% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units directly from our general partner or its affiliates or any transferee of that person or group that is approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner. Please read "—Meetings; Voting."

Limited Call Right

If at any time our general partner and its affiliates own more than 80.0% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining limited partner interests of the class held by unaffiliated persons as of a record date to be

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selected by our general partner, on at least 10, but not more than 60, days notice. The purchase price in the event of this purchase is the greater of:

•: the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and
•: the average of the daily closing prices of the partnership securities of such class for the 20 consecutive trading days preceding the date three days before the date the notice is mailed.

As a result of our general partner's right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read "Material Federal Income Tax Consequences—Disposition of Common Units."

Meetings; Voting

Except as described below regarding a person or group owning 20.0% or more of any class of units then outstanding, unitholders who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20.0% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. The units representing the general partner interest are units for distribution and allocation purposes, but do not entitle our general partner to any vote other than its rights as general partner under our partnership agreement, will not be entitled to vote on any action required or permitted to be taken by the unitholders and will not count toward or be considered outstanding when calculating required votes, determining the presence of a quorum, or for similar purposes.

Each record holder of a unit has a vote according to its percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read "—Issuance of Additional Securities." However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20.0% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum, or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units as a single class.

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Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units will be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described above under "—Limited Liability," the common units will be fully paid, and unitholders will not be required to make additional contributions.

Non-Citizen Assignees; Redemption

If our general partner, with the advice of counsel, determines we are subject to U.S. federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

•: obtain proof of the nationality, citizenship or other related status of our member (and their owners, to the extent relevant); and
•: permit us to redeem the units held by any person whose nationality, citizenship or other related status creates substantial risk of cancellation or forfeiture of any property or who fails to comply with the procedures instituted by our general partner to obtain proof of the nationality, citizenship or other related status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Non-Taxpaying Assignees; Redemption

In the event any rates that we charge our customers become regulated by the Federal Energy Regulatory Commission, to avoid any adverse effect on the maximum applicable rates chargeable to customers by us, or in order to reverse an adverse determination that has occurred regarding such maximum rate, our partnership agreement provides our general partner the power to amend the agreement. If our general partner, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by us, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

•: obtain proof of the U.S. federal income tax status of our member (and their owners, to the extent relevant); and
•: permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates or who fails to comply with the procedures instituted by our general partner to obtain proof of the U.S. federal income tax status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

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Indemnification

Under our partnership agreement, we will indemnify the following persons, in most circumstances, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

•: our general partner;
•: any departing general partner;
•: any person who is or was an affiliate of our general partner or any departing general partner;
•: any person who is or was a member, manager, partner, director, officer, fiduciary or trustee of our partnership, our subsidiaries, our general partner, any departing general partner or any of their affiliates;
•: any person who is or was serving at the request of the general partner or any departing general partner as an officer, director, member, manager, partner, fiduciary or trustee of another person owing a fiduciary duty to us or any of our subsidiaries; and
•: any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep or cause to be kept appropriate books and records of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For fiscal and tax reporting purposes, we use the calendar year.

We will furnish or make available to record holders of common units, within 105 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants, including a balance sheet and statements of operations, and our equity and cash flows. Except for our fourth quarter, we will also furnish or make available summary financial information within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website that we maintain.

We will furnish each record holder with information reasonably required for federal and state tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to

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assist him in determining its federal and state tax liability and filing its federal and state income tax returns, regardless of whether he supplies us with the necessary information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to its interest as a limited partner, upon reasonable demand and at its own expense, have furnished to him:

•: a current list of the name and last known business, residence or mailing address of each partner;
•: a copy of our federal, state and local income tax returns;
•: true and full information as to the amount of cash, and a description and statement of the net agreed value of any other capital contribution by each partner and that each partner has agreed to contribute in the future, and the date on which each became a partner;
•: copies of our partnership agreement, the certificate of limited partnership of the partnership, related amendments, and powers of attorney under which they have been executed;
•: information regarding the status of our business and financial condition; and
•: any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner determines is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the right to information that a limited partner would otherwise have under Delaware law.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units, or other partnership securities proposed to be sold by our general partner or any of its affiliates, other than individuals, or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years and for so long thereafter as is required for the holder to sell its partnership securities following any withdrawal or removal of Summit Midstream GP, LLC as our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read "Units Eligible for Future Sale."

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered by this prospectus, Summit Investments will hold an aggregate of common units and subordinated units (or common units and subordinated units if the underwriters exercise their option to purchase additional units in full). All of the subordinated units will convert into common units at the end of the subordination period. The sale of these common and subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an "affiliate" of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

•: 1.0% of the total number of the securities outstanding; or
•: the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell common units under Rule 144 without regard to the rule's public information requirements, volume limitations, manner of sale provisions and notice requirements.

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read "The Partnership Agreement—Issuance of Additional Securities."

Under our partnership agreement, our general partner and its affiliates, excluding any individual who is an affiliate of our general partner, have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any common units that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any common units to require registration of any of these common units and to include any of these common units in a registration by us of other common units, including common units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following the withdrawal or removal of our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, our general partner and its affiliates may sell their common units in private transactions at any time, subject to compliance with applicable laws.

Summit Investments, our general partner, each of our general partner's directors and officers and other owners have agreed that for a period of 180 days from the date of this prospectus they will not, without the prior written consent of Barclays Capital Inc., dispose of or hedge any common units or any securities convertible into or exchangeable for our common units. Please read "Underwriting" for a description of these lock-up provisions.

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MATERIAL FEDERAL INCOME TAX CONSEQUENCES

This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the U.S. and, unless otherwise noted in the following discussion, is the opinion of Latham & Watkins LLP, counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the "Internal Revenue Code"), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the "Treasury Regulations") and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to "us" or "we" are references to Summit Midstream Partners, LP and our operating subsidiaries.

The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the U.S. and has only limited application to corporations, estates, entities treated as partnerships for U.S. federal income tax purposes, trusts, nonresident aliens, U.S. expatriates and former citizens or long-term residents of the United States or other unitholders subject to specialized tax treatment, such as banks, insurance companies and other financial institutions, tax-exempt institutions, foreign persons (including, without limitation, controlled foreign corporations, passive foreign investment companies and non-U.S. persons eligible for the benefits of an applicable income tax treaty with the United States), IRAs, real estate investment trusts (REITs) or mutual funds, dealers in securities or currencies, traders in securities, U.S. persons whose "functional currency" is not the U.S. dollar, persons holding their units as part of a "straddle," "hedge," "conversion transaction" or other risk reduction transaction, and persons deemed to sell their units under the constructive sale provisions of the Code. In addition, the discussion only comments, to a limited extent, on state, local, and foreign tax consequences. Accordingly, we encourage each prospective unitholder to consult his own tax advisor in analyzing the state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Latham & Watkins LLP. Unlike a ruling, an opinion of counsel represents only that counsel's best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements as to matters of federal income tax law and legal conclusions with respect thereto, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Latham & Watkins LLP and are based on the accuracy of the representations made by us.

For the reasons described below, Latham & Watkins LLP has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales"); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read "—Disposition of Common Units—Allocations Between Transferors and Transferees"); and

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(iii) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read "—Tax Consequences of Unit Ownership—Section 754 Election" and "—Uniformity of Units").

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner's adjusted basis in his partnership interest. Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the "Qualifying Income Exception," exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of "qualifying income." Qualifying income includes income and gains derived from the transportation, processing, storage and marketing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Latham & Watkins LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate "qualifying income" under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Latham & Watkins LLP on such matters. It is the opinion of Latham & Watkins LLP that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below that:

•: We will be classified as a partnership for federal income tax purposes; and
•: Each of our operating subsidiaries will be disregarded as an entity separate from us for federal income tax purposes.

In rendering its opinion, Latham & Watkins LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Latham & Watkins LLP has relied include:

•: Neither we nor any of the operating subsidiaries has elected or will elect to be treated as a corporation; and
•: For each taxable year, more than 90% of our gross income has been and will be income of the type that Latham & Watkins LLP has opined or will opine is "qualifying income" within the meaning of Section 7704(d) of the Internal Revenue Code.

�� We believe that these representations have been true in the past and expect that these representations will continue to be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed

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corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were taxed as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder's tax basis in his common units, or taxable capital gain, after the unitholder's tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder's cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on Latham & Watkins LLP's opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders of Summit Midstream Partners, LP will be treated as partners of Summit Midstream Partners, LP for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of Summit Midstream Partners, LP for federal income tax purposes.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales."

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their tax advisors with respect to their tax consequences of holding common units in Summit Midstream Partners, LP. The references to "unitholders" in the discussion that follows are to persons who are treated as partners in Summit Midstream Partners, LP for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

Subject to the discussion below under "—Entity-Level Collections," we will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. The income we allocate to unitholders will generally be taxable as ordinary income. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

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Treatment of Distributions

Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder's tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under "—Disposition of Common Units." Any reduction in a unitholder's share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as "nonrecourse liabilities," will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder's "at-risk" amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read "—Limitations on Deductibility of Losses."

A decrease in a unitholder's percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder's share of our "unrealized receivables," including depreciation recapture, depletion recapture and/or substantially appreciated "inventory items," each as defined in the Internal Revenue Code, and collectively, "Section 751 Assets." To that extent, the unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder's realization of ordinary income, which will equal the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder's tax basis (often zero) for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending , 2014, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct.

The actual ratio of allocable taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

•: gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units; or

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•: we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Basis of Common Units

A unitholder's initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder's share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner to the extent of the general partner's "net value" as defined in regulations under Section 752 of the Internal Revenue Code, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read "—Disposition of Common Units—Recognition of Gain or Loss."

Limitations on Deductibility of Losses

The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50% of the value of the corporate unitholder's stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be "at risk" with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder's tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder's at-risk amount will increase or decrease as the tax basis of the unitholder's units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer's income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder's investments in

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other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder's share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

A unitholder's share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer's "investment interest expense" is generally limited to the amount of that taxpayer's "net investment income." Investment interest expense includes:

•: interest on indebtedness properly allocable to property held for investment;
•: our interest expense attributed to portfolio income; and
•: the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder's share of our portfolio income will be treated as investment income.

Entity-Level Collections

If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.

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Specified items of our income, gain, loss and deduction will be allocated to account for (i) any difference between the tax basis and fair market value of our assets at the time of an offering and (ii) any difference between the tax basis and fair market value of any property contributed to us by the general partner and its affiliates that exists at the time of such contribution, together referred to in this discussion as the "Contributed Property." The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future, "reverse Section 704(c) Allocations," similar to the Section 704(c) Allocations described above, will be made to the general partner and all of our unitholders immediately prior to such issuance or other transactions to account for the difference between the "book" basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner's "book" capital account, credited with the fair market value of Contributed Property, and "tax" capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the "Book-Tax Disparity," will generally be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction only if the allocation has "substantial economic effect." In any other case, a partner's share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

•: his relative contributions to us;
•: the interests of all the partners in profits and losses;
•: the interest of all the partners in cash flow; and
•: the rights of all the partners to distributions of capital upon liquidation.

Latham & Watkins LLP is of the opinion that, with the exception of the issues described in "—Section 754 Election" and "—Disposition of Common Units—Allocations Between Transferors and Transferees," allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction.

Treatment of Short Sales

A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

•: any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;
•: any cash distributions received by the unitholder as to those units would be fully taxable; and
•: all of these distributions would appear to be ordinary income.

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Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Latham & Watkins LLP has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read "—Disposition of Common Units—Recognition of Gain or Loss."

Alternative Minimum Tax

Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates

Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 15%. These rates are scheduled to sunset after December 31, 2012, and, further, are subject to change by new legislation at any time.

The recently enacted Patient Protection and Affordable Care Act of 2010, as amended by the Health Care and Education Reconciliation Act of 2010 is scheduled to impose a 3.8% Medicare tax on certain net investment income earned by individuals, estates and trusts for taxable years beginning after December 31, 2012. For these purposes, net investment income generally includes a unitholder's allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder's net investment income or (ii) the amount by which the unitholder's modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election

We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS unless there is a constructive termination of the partnership. Please read "—Disposition of Common Units—Constructive Termination." The election will generally permit us to adjust a common unit purchaser's tax basis in our assets ("inside basis") under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply with respect to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in our assets with respect to a unitholder will be considered to have two components: (i) his share of our tax basis in our assets ("common basis") and (ii) his Section 743(b) adjustment to that basis.

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We will adopt the remedial allocation method as to all our properties. Where the remedial allocation method is adopted, the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property that is subject to depreciation under Section 168 of the Internal Revenue Code and whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property's unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read "—Uniformity of Units."

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property's unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read "—Uniformity of Units." A unitholder's tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual's income tax return) so that any position we take that understates deductions will overstate the common unitholder's basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read "—Disposition of Common Units—Recognition of Gain or Loss." Latham & Watkins LLP is unable to opine as to whether our method for depreciating Section 743 adjustments is sustainable for property subject to depreciation under Section 167 of the Internal Revenue Code or if we use an aggregate approach as described above, as there is no direct or indirect controlling authority addressing the validity of these positions. Moreover, the IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

A Section 754 election is advantageous if the transferee's tax basis in his units is higher than the units' share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee's tax basis in his units is lower than those units' share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally, a built-in loss or a basis reduction is substantial if it exceeds $250,000.

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The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read "—Disposition of Common Units—Allocations Between Transferors and Transferees."

Initial Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by our general partner and its affiliates, and (ii) any other offering will be borne by our general partner and all of our unitholders as of that time. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction."

To the extent allowable, we may elect to use the depreciation and cost recovery methods, including bonus depreciation to the extent available, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Please read "—Uniformity of Units." Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction" and "—Disposition of Common Units—Recognition of Gain or Loss."

The costs we incur in selling our units (called "syndication expenses") must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication

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expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties.

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder's tax basis for the units sold. A unitholder's amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder's share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us that in the aggregate were in excess of cumulative net taxable income for a common unit and, therefore, decreased a unitholder's tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder's tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a "dealer" in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at a maximum U.S. federal income tax rate of 15%. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other "unrealized receivables" or to "inventory items" we own. The term "unrealized receivables" includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an "equitable apportionment" method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner's tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner's entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred.

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Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an "appreciated" partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

•: a short sale;
•: an offsetting notional principal contract; or
•: a futures or forward contract;

in each case, with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the "Allocation Date." However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations as there is no direct or indirect controlling authority on this issue. Recently, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Latham & Watkins LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders because the issue has not been finally resolved by the IRS or the courts. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder's interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under

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future Treasury Regulations. A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements

A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the U.S. and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination

We will be considered to have been terminated for tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders could receive two Schedules K-1 if the relief discussed below is not available) for one fiscal year and the cost of the preparation of these returns will be borne by all common unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination. The IRS has recently announced a publicly traded partnership technical termination relief procedure whereby if a publicly traded partnership that has technically terminated requests publicly traded partnership technical termination relief and the IRS grants such relief, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read "—Tax Consequences of Unit Ownership—Section 754 Election." We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property's unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be

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inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read "—Tax Consequences of Unit Ownership—Section 754 Election." To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. In either case, and as stated above under "—Tax Consequences of Unit Ownership—Section 754 Election," Latham & Watkins LLP has not rendered an opinion with respect to these methods. Moreover, the IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read "—Disposition of Common Units—Recognition of Gain or Loss."

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units. Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the U.S. because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, our quarterly distribution to foreign unitholders will be subject to withholding at the highest applicable effective tax rate. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our earnings and profits, as adjusted for changes in the foreign corporation's "U.S. net equity," that is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the U.S. and the country in which the foreign corporate unitholder is a "qualified resident." In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

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A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of "effectively connected income," a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder's gain would be effectively connected with that unitholder's indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the five-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder's share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Latham & Watkins LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year's tax liability, and possibly may result in an audit of his return. Any audit of a unitholder's return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the "Tax Matters Partner" for these purposes. Our partnership agreement names our general partner as our Tax Matters Partner.

The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders

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having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

•

the name, address and taxpayer identification number of the beneficial owner and the nominee;

•

whether the beneficial owner is:

•: a person that is not a U.S. person;
•: a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or
•: a tax-exempt entity;

•

the amount and description of units held, acquired or transferred for the beneficial owner; and

•

specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from dispositions.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1,500,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties.

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

•: for which there is, or was, "substantial authority"; or
•: as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an "understatement" of income for which no "substantial authority" exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take

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other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to "tax shelters," which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (a) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer's gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation or certain other thresholds are met, the penalty imposed increases to 40%. We do not anticipate making any valuation misstatements.

In addition, the 20% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.

Reportable Transactions.

If we were to engage in a "reportable transaction," we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a "listed transaction" or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read "—Information Returns and Audit Procedures."

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following additional consequences:

•: accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at "—Accuracy-Related Penalties";
•: for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and
•: in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any "reportable transactions."

Recent Legislative Developments

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Currently, one such legislative proposal would eliminate the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. Please read "—Partnership Status." We are unable to predict whether any such changes will ultimately be enacted.

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However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our units.

State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We will initially own property and do business in Texas and Colorado. Colorado imposes a personal income tax on individuals, and both Texas and Colorado impose an income tax on corporations and other entities. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder's income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read "—Tax Consequences of Unit Ownership—Entity-Level Collections." Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states, localities and foreign jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of him. Latham & Watkins LLP has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

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INVESTMENT IN SUMMIT MIDSTREAM PARTNERS, LP BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA, collectively, "Similar Laws." For these purposes the term "employee benefit plan" includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs or annuities established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include "plan assets" of such plans, accounts and arrangements, collectively, "Employee Benefit Plans." Among other things, consideration should be given to:

•: whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;
•: whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;
•: whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read "Material Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors"; and
•: whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws.

The person with investment discretion with respect to the assets of an Employee Benefit Plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit Employee Benefit Plans from engaging, either directly or indirectly, in specified transactions involving "plan assets" with parties that, with respect to the Employee Benefit Plan, are "parties in interest" under ERISA or "disqualified persons" under the Internal Revenue Code unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the Employee Benefit Plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner would also be a fiduciary of such Employee Benefit Plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code, ERISA and any other applicable Similar Laws.

The Department of Labor regulations and Section 3(42) of ERISA provide guidance with respect to whether, in certain circumstances, the assets of an entity in which Employee Benefit Plans acquire equity interests would be deemed "plan assets." Under these rules, an entity's assets would not be considered to be "plan assets" if, among other things:

•: (a) the equity interests acquired by the Employee Benefit Plan are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, are freely transferable and are registered under certain provisions of the federal securities laws;

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•: (b) the entity is an "operating company,"—i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or
•: (c) there is no significant investment by "benefit plan investors," which is defined to mean that less than 25% of the value of each class of equity interest, disregarding any such interests held by our general partner, its affiliates and some other persons, is held generally by Employee Benefit Plans.

Our assets should not be considered "plan assets" under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above.

In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws.

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UNDERWRITING

Barclays Capital Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Goldman, Sachs & Co. and Morgan Stanley & Co. LLC are acting as representatives of the underwriters and as joint book-running managers of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement relating to this prospectus, each of the underwriters named below has severally agreed to purchase from us the respective number of common units shown opposite its name below:

Underwriters		Number of Common Units

Barclays Capital Inc.
Merrill Lynch, Pierce, Fenner & Smith Incorporated
Goldman, Sachs & Co.
Morgan Stanley & Co. LLC

Total

The underwriting agreement provides that the underwriters' obligation to purchase the common units depends on the satisfaction of the conditions contained in the underwriting agreement including:

•: the obligation to purchase all of the common units offered hereby (other than those common units covered by their option to purchase additional common units as described below), if any of the common units are purchased;
•: the representations and warranties made by us to the underwriters are true;
•: there is no material change in our business or the financial markets; and
•: we deliver customary closing documents to the underwriters.

Commissions and Expenses

The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional common units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the common units.

	No Exercise	Full Exercise

Per common unit	$	$
Total	$	$

We will pay a structuring fee equal to % of the gross proceeds from this offering (including any proceeds from the exercise of the option to purchase additional common units) to Barclays Capital Inc. for the evaluation, analysis and structuring of our partnership.

The representatives of the underwriters have advised us that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $ per common unit. After the offering, the representatives may change the offering price and other selling terms. Sales of common units made outside of the United States may be made by affiliates of the underwriters. The offering of the common units by the underwriters is subject to receipt and acceptance and subject to the underwriters' right to reject any order in whole or in part.

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We estimate that the expenses of this offering incurred by us will be $ million (excluding underwriting discounts and commissions and a structuring fee).

Option to Purchase Additional Common Units

We have granted the underwriters an option exercisable for 30 days after the date of the underwriting agreement, to purchase, from time to time, in whole or in part, up to an aggregate of additional common units at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than common units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional common units based on the underwriter's underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting section.

Lock-Up Agreements

We, our general partner and its affiliates, including Summit Investments, and the directors and executive officers of our general partner have agreed that, without the prior written consent of Barclays Capital Inc., we and they will not directly or indirectly, (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any of our common units (including, without limitation, common units that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the SEC and common units that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for common units, (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of the common units, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any common units or securities convertible, exercisable or exchangeable into common units or any of our other securities or (4) publicly disclose the intention to do any of the foregoing for a period of 180 days after the date of this prospectus.

The 180-day restricted period described in the preceding paragraph will be extended if:

•: during the last 17 days of the 180-day restricted period we issue an earnings release or material news or a material event relating to us occurs; or
•: prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period, in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or occurrence of the material event unless such extension is waived in writing by Barclays Capital Inc.

Barclays Capital Inc., in its sole discretion, may release the common units and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release the common units and other securities from lock-up agreements, Barclays Capital Inc. will consider, among other factors, the holder's reasons for requesting the release, the number of common units and other securities for which the release is being requested and market conditions at the time.

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Offering Price Determination

Prior to this offering, there has been no public market for our common units. The initial public offering price will be negotiated among the representatives and us. In determining the initial public offering price of our common units, the representatives will consider:

•: the history and prospects for the industry in which we compete;
•: our financial information;
•: the ability of our management and our business potential and earning prospects;
•: the prevailing securities markets at the time of this offering; and
•: the recent market prices of, and the demand for, publicly traded common units of generally comparable companies.

Indemnification

We and certain of our affiliates, including Summit Investments, have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.

Stabilization, Short Positions and Penalty Bids

The representatives may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common units, in accordance with Regulation M under the Exchange Act:

•: Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.
•: A short position involves a sale by the underwriters of common units in excess of the number of common units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of common units involved in the sales made by the underwriters in excess of the number of common units they are obligated to purchase is not greater than the number of common units that they may purchase by exercising their option to purchase additional common units. In a naked short position, the number of common units involved is greater than the number of common units in their option to purchase additional common units. The underwriters may close out any short position by either exercising their option to purchase additional common units and/or purchasing common units in the open market. In determining the source of common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option to purchase additional common units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.
•: Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions.
•: Penalty bids permit the representative to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

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These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Electronic Distribution

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter's or selling group member's web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

New York Stock Exchange

We intend to apply to list our common units on the New York Stock Exchange under the symbol "SMLP." The underwriters have undertaken to sell the minimum number of common units to the minimum number of beneficial owners necessary to meet the New York Stock Exchange distribution requirements for trading.

Discretionary Sales

The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of common units offered by them.

Stamp Taxes

If you purchase common units offered by this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

Relationships

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include sales and trading, commercial and investment banking, advisory, investment management, investment research, principal investment, hedging, market making, brokerage and other financial and non-financial activities and services. The underwriters and their affiliates have

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in the past, and may in the future, perform investment banking, commercial banking, advisory and other services for us and our respective affiliates from time to time for which they have received, and may in the future receive, customary fees and expenses.

In addition, in the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers. Such investment and securities activities may involve securities and instruments of ours or our affiliates. The underwriters and their affiliates may also make investment recommendations or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long or short positions in such securities and instruments.

Affiliates of Barclays Capital Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Goldman, Sachs & Co. and Morgan Stanley & Co. LLC are lenders under our amended and restated revolving credit facility and, in that respect, will receive a portion of the net proceeds from this offering.

FINRA

Because the Financial Industry Regulatory Authority, Inc., or FINRA, is expected to view the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2310 of the FINRA Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Selling Restrictions

European Economic Area

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a "relevant member state"), other than Germany, with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state, an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:

•: to any legal entity which is a qualified investor as defined in the Prospectus Directive;
•: to fewer than 100 or, if the relevant member state has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant dealer or dealers nominated by the issuer for any such offer; or
•: in any other circumstances falling within Article 3(2) of the Prospectus Directive;

provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an "offer of securities to the public" in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression "Prospectus Directive" means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the relevant member state), and includes any relevant implementing

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measure in each relevant member state. The expression "2010 PD Amending Directive" means Directive 2010/73/EU.

We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

United Kingdom

We may constitute a "collective investment scheme" as defined by section 235 of the Financial Services and Markets Act 2000, or FSMA, that is not a "recognized collective investment scheme" for the purposes of FSMA, or CIS, and that has not been authorized or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and is only directed at:

(i) if we are a CIS and are marketed by a person who is an authorized person under FSMA, (a) investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) (Exemptions) Order 2001, as amended, or the CIS Promotion Order, or (b) high net worth companies and other persons falling within Article 22(2)(a) to (d) of the CIS Promotion Order; or

(ii) otherwise, if marketed by a person who is not an authorized person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended, or Financial Promotion Order, or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and

(iii) in both cases (i) and (ii) to any other person to whom it may otherwise lawfully be made, (all such persons together being referred to as "relevant persons"). The common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this prospectus or any of its contents.

An invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) in connection with the issue or sale of any common units which are the subject of the offering contemplated by this prospectus will only be communicated or caused to be communicated in circumstances in which Section 21(1) of FSMA does not apply to us.

Switzerland

This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. The common units are not being offered to the public in Switzerland, and neither this prospectus, nor any other offering materials relating to the common units may be distributed in connection with any such public offering.

We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006, or the CISA. Accordingly, the common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to the common units may be made available through a public offering in or from Switzerland. The common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private

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placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

Germany

This document has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Sales Prospectus Act (Verkaufsprospektgesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht—BaFin) nor any other German authority has been notified of the intention to distribute our common units in Germany. Consequently, our common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this document and any other document relating to the offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of our common units to the public in Germany or any other means of public marketing. Our common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities Prospectus Act, Section 8f paragraph 2 no. 4 of the German Sales Prospectus Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This document is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

The offering does not constitute an offer to sell or the solicitation or an offer to buy our common units in any circumstances in which such offer or solicitation is unlawful.

Netherlands

Our common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

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VALIDITY OF THE COMMON UNITS

The validity of the common units offered hereby will be passed upon for us by Latham & Watkins LLP, Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

The consolidated financial statements of Summit Midstream Partners, LLC and subsidiaries as of December 31, 2011 and 2010 (Successor), and the related consolidated statements of operations, membership interests, and cash flows for the years ended December 31, 2011 and 2010 (Successor), for the period from September 3, 2009 (Inception) through December 31, 2009 (Successor) and for the period from January 1, 2009 through September 3, 2009 (Predecessor) included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein (which report expresses an unqualified opinion and includes an explanatory paragraph related to Summit Midstream Partners, LLC's acquisition of (1) the Grand River system from Encana Corporation on October 27, 2011 and (2) DFW Midstream Services LLC from Energy Future Holdings Corp., effective September 3, 2009). Such financial statements have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The balance sheet of Summit Midstream Partners, LP included in this prospectus has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein. Such financial statement has been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered in this prospectus, you may desire to review the full registration statement, including the exhibits. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of this material can also be obtained upon written request from the Public Reference Section of the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549 at prescribed rates or from the SEC's web site on the Internet at http://www.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on public reference rooms.

As a result of the offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC's website as provided above. Our website is located at and will be activated in connection with the closing of this offering. We expect to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

We intend to furnish or make available to our unitholders annual reports containing our audited financial statements prepared in accordance with GAAP. Our annual report will contain a detailed statement of any transactions with our general partner or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to our general partner or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed. We also intend to furnish or make available to our unitholders quarterly reports containing our unaudited

215

interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including "will," "may," "believe," "expect," "anticipate," "estimate," "continue," or other similar words. These statements discuss future expectations, contain projections of financial condition or of results of operations, or state other "forward-looking" information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement.

216

INDEX TO FINANCIAL STATEMENTS

		Page

Summit Midstream Partners, LLC and Subsidiaries
Unaudited Historical Condensed Consolidated Financial Statements as of March 31, 2012 and December 31, 2011, and for the Three Months Ended March 31, 2012 and 2011:
Condensed Consolidated Balance Sheets		F-2
Condensed Consolidated Statements of Operations		F-3
Condensed Consolidated Statements of Membership Interests		F-4
Condensed Consolidated Statements of Cash Flows		F-5
Notes to Condensed Consolidated Financial Statements		F-6
Historical Consolidated Financial Statements as of December 31, 2011 and 2010 (Successor) and for the Years Ended December 31, 2011 and 2010 (Successor), for the Period from September 3, 2009 (Inception) through December 31, 2009 (Successor), and for the Period from January 1, 2009 through September 3, 2009 (Predecessor):
Report of Independent Registered Public Accounting Firm		F-20
Consolidated Balance Sheets		F-21
Consolidated Statements of Operations		F-22
Consolidated Statements of Membership Interests		F-23
Consolidated Statements of Cash Flows		F-24
Notes to Consolidated Financial Statements		F-26
Summit Midstream Partners, LP
Report of Independent Registered Public Accounting Firm		F-48
Balance Sheet as of May 10, 2012		F-49
Notes to Balance Sheet		F-50

F-1

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Dollars in Thousands

	Supplemental Pro forma March 31, 2012		March 31, 2012		December 31, 2011

	(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	10,911	$	10,911	$	15,462
Accounts receivable		30,997		30,997		27,476
Other assets		1,358		1,358		1,966

Total current assets		43,266		43,266		44,904
PROPERTY, PLANT, AND EQUIPMENT—Net (Note 5)		652,732		652,732		642,552
OTHER NONCURRENT ASSETS		5,451		5,451		4,979
INTANGIBLE ASSETS—Net (Note 4):
Favorable contract		21,354		21,354		21,673
Contracts		276,238		276,238		279,588
Rights-of-way		33,123		33,123		32,802

TOTAL ASSETS	$	1,032,164	$	1,032,164	$	1,026,498

LIABILITIES AND MEMBERSHIP INTERESTS
CURRENT LIABILITIES:
Accounts payable—trade	$	15,137	$	15,137	$	22,420
Other current liabilities		3,095		3,095		4,971
Distribution payable to Sponsors (Note 1)				—		—

Total current liabilities				18,232		27,391
PROMISSORY NOTES PAYABLE TO SPONSORS (Note 7)		206,940		206,940		202,893
REVOLVING CREDIT FACILITY (Note 6)		147,000		147,000		147,000
NONCURRENT LIABILITIES—Net (Note 4)		8,491		8,491		8,944
DEFERRED REVENUE		3,184		3,184		—

Total liabilities				383,847		386,228

COMMITMENTS AND CONTINGENCIES (Note 10)
MEMBERSHIP INTERESTS (Note 9)				648,317		640,270

TOTAL LIABILITIES AND MEMBERSHIP INTERESTS	$	1,032,164	$	1,032,164	$	1,026,498

The accompanying notes are an integral part of these unaudited condensed consolidated
financial statements.

F-2

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

Dollars in Thousands

	For the three months ended March 31,

	2012			2011
REVENUES:
Gathering services and other fees	$	31,918		$	17,128
Natural gas and condensate sales		3,731			2,117
Amortization of favorable and unfavorable contracts		134			(70	)

Total revenues		35,783			19,175

COSTS AND EXPENSES:
Operation and maintenance		10,989			6,148
General and administrative		4,412			3,843
Transaction costs		193			—
Depreciation and amortization		8,290			1,605

Total costs and expenses		23,884			11,596

OTHER INCOME		4			5
INTEREST EXPENSE		(695	)		—
AFFILIATED INTEREST EXPENSE		(3,482	)		—

INCOME BEFORE INCOME TAXES		7,726			7,584
INCOME TAX EXPENSE		(139	)		(73	)

NET INCOME	$	7,587		$	7,511

Supplemental unaudited pro forma earnings per common unit (See Note 1)	$

The accompanying notes are an integral part of these unaudited condensed consolidated
financial statements.

F-3

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF MEMBERSHIP INTERESTS (UNAUDITED)

Dollars in Thousands

	Membership Interests

BALANCE—December 31, 2011	$	640,270
Class B membership interest based compensation		460
Net income		7,587

BALANCE—March 31, 2012	$	648,317

BALANCE—December 31, 2010	$	307,370
Contributions from Sponsors		8,000
Class B membership interest based compensation		1,214
Net income		7,511

BALANCE—March 31, 2011	$	324,095

The accompanying notes are an integral part of these unaudited condensed consolidated
financial statements.

F-4

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE THREE MONTHS ENDED (UNAUDITED)

Dollars in Thousands

	For the three months ended March 31,

	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	7,587		$	7,511
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		8,290			1,605
Amortization of favorable and unfavorable contracts		(134	)		70
Amortization of deferred loan costs		233			—
Pay in kind interest on promissory notes payable to Sponsors		3,482			—
Class B membership interest based compensation expense		460			1,214
Changes in operating assets and liabilities:
Accounts receivable		(3,521	)		(382	)
Accounts payable—trade		(1,671	)		(293	)
Other assets		571			(51	)
Increase in deferred revenue		3,184			—
Other current liabilities		(1,876	)		(819	)

Cash provided by operating activities		16,605			8,855

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(20,577	)		(19,606	)

Cash used in investing activities		(20,577	)		(19,606	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Contributions from sponsors		—			8,000
Initial public offering costs		(579	)		—

Cash (used in) provided by financing activities		(579	)		8,000

NET CHANGE IN CASH AND CASH EQUIVALENTS		(4,551	)		(2,751	)
CASH AND CASH EQUIVALENTS—Beginning of period		15,462			9,421

CASH AND CASH EQUIVALENTS—End of period	$	10,911		$	6,670

SUPPLEMENTAL SCHEDULE OF INVESTING AND FINANCING ACTIVITIES:
Cash interest paid	$	1,695		$	—
Capitalized interest		(1,321	)		—

Interest paid (net of capitalized interest)	$	374		$	—

Cash paid for taxes	$	—		$	—

SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Capital expenditures in accounts payable (period end accruals)	$	5,629		$	9,782

Pay in kind interest	$	4,047		$	—

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

F-5

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

1. ORGANIZATION AND BUSINESS OPERATIONS

Organization—Summit Midstream Partners, LLC (the "Company" or "Summit Midstream"), a Delaware limited liability company, was formed and began operations on September 3, 2009. The Company is the predecessor for accounting purposes of Summit Midstream Partners, LP ("SMLP") who submitted a registration statement for its initial public offering of common units on a confidential basis. The Company's business strategy is to own and operate a portfolio of midstream energy infrastructure assets that are strategically located in the core areas of unconventional resource basins in North America. Through August 17, 2011, the Company was wholly-owned by Energy Capital Partners II, LP and its parallel and co-investment funds (collectively, "Energy Capital Partners" or "Sponsor"). On August 17, 2011, Energy Capital Partners sold an 11.25% membership interest in the Company to a subsidiary of GE Energy Financial Services, Inc. ("GE Energy Financial Services" or "Sponsor", collectively with Energy Capital Partners, "Sponsors"). Subsequent to the sale of this noncontrolling interest to GE Energy Financial Services, Energy Capital Partners continues to control the activities of Summit Midstream through its representation on the Company's board of managers. Certain members of the Summit Midstream management hold ownership interests in the form of Class B membership interests in Summit Midstream (the "SMP Net Profits Interests") through their ownership in Summit Midstream Management, LLC.

On October 4, 2011, the Company entered into a purchase and sale agreement with Encana Oil & Gas (USA) Inc., a subsidiary of Encana Corporation ("Encana"), to acquire certain natural gas gathering pipeline, dehydration and compression assets in western Colorado for $590 million. These assets gather production from the Mamm Creek, Orchard, and South Parachute fields in the area around Rifle, Colorado. The assets gather natural gas under long-term contracts ranging from 10-25 years. In addition to the purchase, the Company has a contractual relationship with Encana related to the development of midstream infrastructure to support Encana's emerging Mancos and Niobrara Shale development. The transaction closed on October 27, 2011, with an effective date of October 1, 2011. The assets are owned by Grand River Gathering, LLC, a wholly owned subsidiary of the Company ("Grand River Gathering"). The transaction was funded through an equity contribution and an aggregate of $200 million in promissory notes from the Sponsors.

Business Operations—Summit Midstream's two operating subsidiaries are DFW Midstream Services LLC ("DFW Midstream") and Grand River Gathering, LLC. Both are midstream energy companies focused on the development, construction and operation of natural gas gathering systems. DFW Midstream's gathering system is located in the core of the Barnett Shale located in the Fort Worth basin in Texas. Grand River Gathering's gathering system is located in the Piceance Basin, which includes the Mesaverde, Mancos and Niobrara Shale formations in western Colorado.

Basis of Presentation and Principles of Consolidation—The unaudited condensed consolidated financial statements include the assets, liabilities, and results of operations of the Company and its wholly-owned subsidiaries Summit Midstream Holdings, LLC ("Holdings"), Grand River Gathering and DFW Midstream, and have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The unaudited condensed consolidated financial statements for the three months ended March 31, 2012 also include the operations of Grand River Gathering. The acquisition of Grand River Gathering closed on October 27, 2011.

F-6

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

1. ORGANIZATION AND BUSINESS OPERATIONS (Continued)

In our opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for a fair presentation of the results of operations for the three months ended March 31, 2012 and 2011. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission ("SEC"). The unaudited condensed consolidated financial statements should be read in conjunction with the audited annual financial statements and related notes elsewhere in this prospectus. The results of operations for an interim period are not necessarily indicative of results expected for a full year. Subsequent events have been evaluated through July 17, 2012, the date these financial statements were available to be issued.

The Company's operations are organized into a single business segment, the assets of which consist of natural gas gathering systems and related plant and equipment.

Supplemental Unaudited Pro Forma Information—Staff Accounting Bulletin 1.B.3 requires that certain distributions to owners prior to or coincident with an initial public offering be considered as distributions in contemplation of that offering. Upon completion of this offering, SMLP intends to distribute approximately $ million in cash to the Sponsors. Supplemental unaudited basic and diluted pro forma earnings per common unit for Summit Midstream Partners, LP for the three months ended March 31, 2012 assumed general partner units, subordinated units and common units were outstanding in the period. The common units consists of common units issued to the Sponsors plus an additional units, which is the number of common units that we would have been required to issue to fund the $ million distribution of net proceeds to the Sponsors. The number of common units that Summit Midstream Partners, LP would have been required to issue to fund the $ million distribution was calculated as $ million minus the Summit Midstream Partners, LLC net earnings of $ million for the year ended December 31, 2011 divided by an issue price per unit of $ , which is the initial public offering price of $ per common unit less the estimated underwriting discounts, structuring fee and offering expenses. There were no securities convertible or exchangeable into common units outstanding to be considered in the pro forma diluted earnings per unit calculation.

The supplemental unaudited pro forma balance sheet as of March 31, 2012 gives pro forma effect to the assumed distribution discussed in the preceding paragraph, as though it had been declared and was payable as of that date.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates—The unaudited condensed consolidated financial statements have been prepared in conformity with GAAP, which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates, the reported amounts of revenue and expense, including fair value measurements, and disclosure of contingencies. Although management believes these estimates are reasonable, actual results could differ from its estimates.

F-7

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Accounts Receivable—Accounts receivable relate to gathering and other services provided to independent natural gas producer customers. Accounts receivable included in the balance sheets are net of an allowance for doubtful accounts. At March 31, 2012 and December 31, 2011, the Company recorded no allowance for doubtful accounts. The Company did not experience non-payment for services during any period presented.

Asset Retirement Obligations—Accounting standards related to asset retirement obligations require the Company to evaluate whether future asset retirement obligations exist as of March 31, 2012 and December 31, 2011, and whether the expected retirement date of the related costs of retirement can be estimated. We have concluded that our natural gas gathering system assets, which include pipelines, compression facilities and dehydration facilities, as having an indeterminate life because they are owned and will operate for an indeterminate future period when properly maintained. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified. The Company did not provide any asset retirement obligations as of March 31, 2012 and December 31, 2011 because it does not have sufficient information to reasonably estimate such obligations, and the Company has no current intention of discontinuing use of any significant assets.

Revenue Recognition—The Company earns revenue from natural gas gathering services provided to natural gas producers and records such revenue as gathering services and other fees. The Company also earns revenue from the sale of physical natural gas retained from its customers to offset power expenses associated with electric-driven compression on the DFW Midstream system and condensate retained from gathering services. The Company records this revenue as natural gas and condensate sales. The Company records costs incurred which are reimbursed by its customers, on a gross basis in the consolidated statements of operations. Revenue is recognized when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price is fixed or determinable, and (iv) collectability is reasonably assured.

The Company's natural gas gathering agreements provide a monthly or annual minimum volume commitment, or MVC, from certain of its customers. Under these monthly or annual MVCs, the Company's customers agree to ship a minimum volume of natural gas on the Company's gathering systems or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. If a customer's actual throughput volumes are less than its MVC for an applicable period, such customer must make a shortfall payment to the Company at the end of that contract month or year, as applicable. Under certain natural gas gathering agreements, customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent periods to the extent that such customer's throughput volumes in subsequent periods exceed its MVC, ranging from twelve months to ten years.

Billings to customers for obligations under their minimum volume commitments are recorded as deferred revenue. The Company recognizes deferred revenue under these arrangements into revenue once all contingencies or potential performance obligations associated with the related volumes have either (1) been satisfied through the gathering of future excess, or (2) expired (or lapsed) through the passage of time pursuant to the terms of the applicable natural gas gathering agreement. The Company

F-8

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

classifies deferred revenue as short-term for arrangements where the expiration of a customer's right to utilized shortfall payments is twelve months or less. As of March 31, 2012, the Company's customers have $3.2 million of shortfall payments, of which $1.8 million is included in accounts receivable as of March 31, 2012, attributed to arrangements that provide for the ability to offset gathering fees in the next one month to nine years to the extent that a customer's throughput volumes exceed its MVC.

Commitments and Contingencies—The consolidated financial results of the Company may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. See Note 10 for a discussion of commitments and contingencies.

Fair Value of Financial Instruments—The carrying amount of cash and cash equivalents, accounts receivable, and accounts payable approximates fair value due to their short-term maturities.

Comprehensive Income—Comprehensive income is the same as net income for all periods presented.

Earnings per Unit—Earnings per unit has not been presented because the Company's members hold interests and not units.

Unit Based Compensation—Certain of our current and former employees received Class B membership interests, classified as net profits interests, in DFW Midstream Management LLC or Summit Midstream Management, LLC (collectively, the "Net Profits Interests"). The Net Profits Interests participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested Net Profits Interests. The Net Profits Interests are accounted for as compensatory awards. The Net Profits Interests vest ratably over four to five years, 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 LLC Agreement). With the assistance of a third-party valuation firm, we determined the fair value of the Net Profits Interests as of the respective grant dates. The Net Profits Interests were valued utilizing an option pricing method, which models the Class A and Class B membership interests as call options on the underlying equity value of either DFW Midstream Management LLC or Summit Midstream Management, LLC, and considers the rights and preferences of each class of equity in order to allocate a fair value to each class. We used a combination of the income and market approaches, including the following assumptions and internal and external factors in determining the grant date fair value of the Net Profits Interests: (a) assumptions underlying the enterprise value used in connection 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, and terminal growth rates; (b) holding period restrictions; (c) discounts for lack of marketability; and (d) expected volatility rates based on the historical and implied volatility of other midstream services companies whose share or option prices are publicly available.

F-9

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recent Accounting Pronouncements—Accounting standard-setting organizations frequently issue new or revised accounting rules. The Company regularly reviews all new pronouncements to determine their impact, if any, on its condensed consolidated financial statements. There are currently no recent pronouncements that have been issued that the Company believes will materially affect its condensed consolidated financial statements.

3. ACQUISITION OF GRAND RIVER GATHERING

The Company completed the acquisition of Grand River Gathering from Encana for $590 million, effective October 1, 2011 (the "Grand River Transaction"). The Grand River Gathering natural gas midstream assets are located in the Piceance Basin. The acquired assets include approximately 270 miles of pipeline and 90,000 horsepower of compression facilities. These assets gather production from the Mamm Creek, Orchard, and South Parachute fields in the area around Rifle, Colorado. The assets gather natural gas under long-term contracts ranging from 10 years to 25 years (weighted average life of 12.8 years). In addition to the purchase, the Company has a contractual relationship with Encana related to the development of midstream infrastructure to support Encana's emerging Mancos and Niobrara Shale development.

The Grand River Transaction closed on October 27, 2011, with an effective date of October 1, 2011. The assets are owned by Grand River Gathering. The Grand River Transaction was funded through an equity contribution of $410 million and promissory notes from the Sponsors totaling $200 million.

The Company accounted for the Grand River Transaction under the acquisition method of accounting, whereby the total purchase price of the Grand River Transaction was allocated to Grand River Gathering's identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values as of October 27, 2011. The intangible assets that were acquired are comprised of gas gathering agreement contract values and right-of-way easements. The fair values were determined based upon assumptions related to future cash flows, discount rates, asset lives, and projected capital expenditures to complete the Grand River Gathering gathering system. The Company has not completed the final purchase price allocation to the assets acquired and liabilities assumed as of March 31, 2012, because the Company is waiting to receive certain information in order to complete its determination of the values of acquired assets under construction, the related impacts on the valuation of the customer contract intangible assets and the final settlement of the purchase price.

F-10

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

3. ACQUISITION OF GRAND RIVER GATHERING (Continued)

Fair values of the assets acquired and liabilities assumed as of October 27, 2011, are as follows:


Purchase price assigned to Grand River Gathering	$	590,000

Property, plant, and equipment		300,000
Gas gathering agreement contract intangibles		282,000
Rights-of-way		8,000

Total assets acquired		590,000

Noncurrent liabilities		—
Other liabilities		—

Total liabilities assumed		—

Net identifiable assets acquired		590,000

Goodwill	$	—

The Company determined that the purchase price was equal to the fair value of the net assets acquired; thus, no goodwill was recorded.

Unaudited Pro Forma Financial Information—The following unaudited pro forma financial information assumes that the Grand River Gathering acquisition occurred on January 1, 2010. The unaudited pro forma information is not necessarily indicative of what the Company's financial position or results of operation would have been if the transactions had occurred on those dates, or what the Company's financial position or results from operations will be for any future periods. These pro forma adjustments were derived by annualizing the actual operating results for Grand River Gathering that we recorded for the two month period from November 1, 2011 through December 31, 2011. The Company incurred transaction costs of $3,160, which are not included in net income presented immediately below, as the pro forma information assumes the transaction occurred January 1, 2010.

	Three Months Ended March 31, 2011

Revenue	$	41,918
Net income	$	13,043

4. IDENTIFIABLE INTANGIBLE ASSETS AND NONCURRENT LIABILITY

On September 3, 2009, the Company acquired a controlling interest in DFW Midstream from Texas Competitive Electric Holdings Company LLC (the "DFW Transaction"). The Company accounted for the DFW Transaction and the Grand River Transaction under the acquisition method of accounting and identified separately identifiable intangible assets and a noncurrent liability. Identifiable

F-11

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

4. IDENTIFIABLE INTANGIBLE ASSETS AND NONCURRENT LIABILITY (Continued)

intangible assets and a noncurrent liability, which are subject to amortization as of March 31, 2012 and December 31, 2011, are composed of the following:

March 31, 2012		Gross Carrying Amount		Accumulated Amortization			Net

Favorable gas gathering contracts	18.7	$	24,195	$	(2,841	)	$	21,354
Contract intangibles	12.4		282,000		(5,762	)		276,238
Rights-of-way	28.3		34,978		(1,855	)		33,123

Total amortizable intangible assets		$	341,173	$	(10,458	)	$	330,715

Unfavorable contract	10	$	10,962	$	(2,471	)	$	8,491

December 31, 2011		Gross Carrying Amount		Accumulated Amortization			Net

Favorable gas gathering contracts	18.7	$	24,195	$	(2,522	)	$	21,673
Contract intangibles	12.4		282,000		(2,412	)		279,588
Rights-of-way	28.3		34,343		(1,541	)		32,802

Total amortizable intangible assets		$	340,538	$	(6,475	)	$	334,063

Unfavorable contract	10	$	10,962	$	(2,018	)	$	8,944

Amortization expense of $319 and $375 for the three month periods ended March 31, 2012 and 2011 related to the favorable gas gathering contract intangible assets was recorded within revenue. The favorable contract relates to a gas gathering contract that was deemed to be above market upon the acquisition of DFW Midstream. The favorable contract intangible assets are amortized on a units-of-production basis over their estimated useful lives, which is the period over which the assets are expected to contribute directly or indirectly to the Company's future cash flows.

Amortization expense of $3,350 for the three month period ended March 31, 2012 related to the intangible contract values of the gas gathering agreements at Grand River Gathering was recorded and is included in the depreciation and amortization expense in the statements of operations. The intangible asset contract values are amortized over the period of economic benefit based upon the expected revenues over the life of the contract.

Amortization expense of $314 and $185 for the three month periods ended March 31, 2012 and 2011 related to rights-of-way associated with city easements and easements granted within existing rights-of-way was recorded within depreciation and amortization expense over the shorter of the contractual term of the rights-of-way, ranging from 20 to 30 years, or the estimated useful life of the gathering system, which is 30 years.

F-12

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

4. IDENTIFIABLE INTANGIBLE ASSETS AND NONCURRENT LIABILITY (Continued)

amortized on a units-of-production basis over its estimated useful life, which is the period over which the liability is expected to contribute directly or indirectly to the Company's future cash flows.

The estimated aggregate amortization of intangible assets and a noncurrent liability for each of the five succeeding fiscal years from March 31, 2012 is as follows:

March 31, 2012	Assets		Liability

2012	$	14,392	$	880
2013		21,465		1,441
2014		24,705		1,549
2015		28,102		1,650
2016		29,690		1,571

There are no indefinite-lived intangible assets recorded as of March 31, 2012 or December 31, 2011.

5. PROPERTY, PLANT, AND EQUIPMENT—NET

Net property, plant, and equipment is composed of the following:

		March 31, 2012			December 31, 2011

Gas gathering system	30	$	366,847		$	335,083
Compressor stations and compression equipment	30		209,211			165,600
Other	4-15		2,502			2,071

Total			578,560			502,754
Less accumulated depreciation			(16,806	)		(12,180	)

Net of accumulated depreciation			561,754			490,574
Construction in progress			90,978			151,978

Property, plant, and equipment—net		$	652,732		$	642,552

Depreciation expense related to property, plant, and equipment was $4,626 and $1,420 for the three months ended March 31, 2012 and 2011. The Company capitalized interest totaling $1,321 and zero during the three months ended March 31, 2012 and 2011.

6. REVOLVING CREDIT FACILITY

F-13

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

6. REVOLVING CREDIT FACILITY (Continued)

subsidiaries. Borrowings under the revolving credit facility bear interest at London Interbank Offered Rate (LIBOR) plus an applicable margin or a base rate, as defined in the credit agreement. Under the terms of the revolving credit facility, the applicable margin under LIBOR borrowings was 2.50% at March 31, 2012. As of March 31, 2012, availability under the revolving credit facility totaled $138 million. The unused portion of the revolving credit facility is subject to a commitment fee of 0.50%. The weighted-average interest rate as of March 31, 2012 was 2.75%.

The revolving credit facility requires Holdings to maintain a ratio of consolidated trailing 12-month EBITDA to net interest expense of not less than 2.5 to 1.0 (as defined in the credit agreement) 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 1.0 for up to six months following certain acquisitions (as defined in the credit agreement). As of March 31, 2012, Holdings was in compliance with all applicable covenants.

The revolving credit facility contains restrictive covenants that prohibit the declaration or payment of distributions by Holdings if a default then exists or would result therefrom, and otherwise limits the amount of distributions Holdings can make. An event of default may result in the acceleration of Holdings' repayment of outstanding borrowings under the revolving credit facility, the termination of the revolving credit facility and foreclosure on collateral. Upon closing of the facility, the Company made a distribution of $132.9 million to Energy Capital Partners. As of March 31, 2012, there was $147 million outstanding under the facility.

On May 7, 2012, Holdings closed on an amendment and restatement of its revolving credit facility, which expanded its borrowing capacity to $550 million from $285 million. Upon closing of the senior secured amended and restated revolving credit facility, the Company contributed its assets and membership interests in Grand River Gathering to Holdings and Holdings borrowed $163 million under the facility (bringing total borrowings under the facility to $310 million). Additionally, Holdings utilized $160 million of the borrowings at closing to partially repay the promissory notes payable to Sponsors. The amended and restated credit facility is secured by the membership interests of Holdings, DFW Midstream and Grand River Gathering and substantially all of Holdings', DFW Midstream's and Grand River Gathering's assets and is guaranteed by Holdings' subsidiaries. The amended and restated revolving credit facility contains affirmative and negative covenants customary for credit facilities of this size and nature, that, among other things, limit or restrict the ability to incur additional debt, make investments, engage in certain mergers, consolidations, acquisitions or sales of assets, enter into swap agreements and power purchase agreements and enter into leases that would cumulatively obligate payments in excess of $30 million over any 12-month period. The interest costs, other fees and financial covenants of the amended and restated revolving credit facility are consistent with the May 2011 revolving credit facility. The amended and restated revolving credit facility matures in May 2016.

7. PROMISSORY NOTES PAYABLE TO SPONSORS

F-14

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

7. PROMISSORY NOTES PAYABLE TO SPONSORS (Continued)

$4,047, resulting in $206,940 as the amount outstanding on the notes as of March 31, 2012. During the three months ended March 31, 2012, the Company capitalized $565 of the $4,047 interest expense related to costs incurred on capital projects under construction. As of March 31, 2012, the aggregate carrying value of these notes approximated the fair value. On May 8, 2012 the Company borrowed $163 million under the amended and restated revolving credit facility and used a portion of the same borrowings to prepay $160 million of the promissory notes payable to sponsors. On July 2, 2012, the Company borrowed $50 million under the amended and restated revolving credit facility and used a portion of the same borrowings to prepay the remaining $49.2 million of the promissory notes payable to Sponsors.

8. INCOME TAXES

No provision for federal income taxes or state income taxes are included in our results of operations as such income is taxable directly to our owners. However, we are subject to income taxes in the state of Texas. In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax (i.e., the Texas Margin Tax), including nontaxable entities such as limited liability companies, limited partnerships, and limited liability partnerships. The tax is assessed on the Texas-sourced taxable margin, which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the Texas Margin Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. The income tax provision recorded in operations associated with the Texas Margin Tax was $139 and $73, for the three months ended March 31, 2012 and 2011.

9. MEMBERSHIP INTERESTS

As of March 31, 2012, Energy Capital Partners holds an 88.75% interest and GE Energy Financial Services holds an 11.25% interest in Summit Midstream. Such membership interests gives the Sponsors the right to participate in distributions and to exercise the other rights or privileges available to each entity under the Company's Amended and Restated Limited Liability Operating Agreement (the "Summit LLC Agreement").

In accordance with the Summit LLC Agreement, capital accounts are maintained for the Company's members. The capital account provisions of the Summit LLC Agreement incorporate principles established for U.S. federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in the Company's condensed consolidated financial statements.

The Summit LLC Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that its membership interest holders will receive. Capital contributions required under the Summit LLC Agreement are in proportion to the members' respective percentage ownership interests. The Summit LLC Agreement also contains provisions for the allocation of net earnings and losses to members. For purposes of maintaining partner capital accounts, the Summit LLC Agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interests described above.

F-15

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

9. MEMBERSHIP INTERESTS (Continued)

During the three months ended March 31, 2012, the Company, with assistance from a third-party valuation expert, determined the fair value of the SMP Net Profits Interests as of the respective grant date for the grant made on January 25, 2012. The SMP Net Profits Interests granted on January 25, 2012, were valued utilizing an option pricing method, which models the Class A and Class B membership interests as call options on the underlying equity value of Summt Midstream Management, LLC, and considers the rights and preferences of each 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 the Company, as well as the length of holding period and volatility of our equity securities. We estimated the enterprise value utilizing a combination of the income and market approaches. The income approach utilized the discounted cash flow method, whereby we applied a discount rate to estimated future cash flows of the Company. Key inputs include forecasted gathering volumes, revenues and costs; unlevered equity betas of the Company's peer group; equity market risk premium; company-specific risk premium; and terminal growth rate. Under the market approach, trading multiples of the securities of publicly-traded peer companies were applied to the Company's estimated future cash flows.

Additional significant inputs used in the option pricing method for the SMP Net Profits Interests granted on January 25, 2012 are as follows:



Length of holding period restriction (in years)	4
Discount for lack of marketability	32.3	%
Volatility	48.7	%

Information regarding the amount and grant-date fair value of the vested and nonvested SMP Net Profits Interests as of March 31, 2012 is presented below.

			Weighted-Average Grant Date Fair Value (per 1.0% of SMP Net Profits Interests)

Nonvested at January 1, 2012	3.958	%	$	1,003.1
Granted	0.500	%	$	1,780.0
Vested	0.318	%	$	964.6

Nonvested at March 31, 2012	4.141	%	$	1,009.8

Vested at March 31, 2012	2.215	%	$	711.6

The Company recognizes compensation expense ratably over the five year vesting period. Non-cash compensation expense (recorded in general and administrative expense) related to the three months ended March 31, 2012 and 2011 was $307 and $111. The Company recorded non-cash compensation expense of $463 during the three months ended March 31, 2011 related to 2010 and 2009. As of March 31, 2012, the unrecognized non-cash compensation expense for the remaining vesting period is

F-16

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

9. MEMBERSHIP INTERESTS (Continued)

$4,554. Incremental non-cash compensation expense will be recorded over the remaining expected weighted average vesting period of 3.9 years.

DFW Net Profits Interests participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested DFW Net Profits Interests. The DFW Net Profits Interests are accounted for as compensatory awards. All grants vest ratably over 4 years 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 an LLC Agreement).

Information regarding the amount and grant-date fair value of the vested and nonvested DFW Net Profits Interests as of March 31, 2012 is presented below.

			Weighted-Average Grant Date Fair Value (per 1.0% of DFW Net Profits Interests)

Nonvested at January 1, 2012	1.750	%	$	305.9
Granted	0.000	%	$	0
Vested	0.275	%	$	277.1

Nonvested at March 31, 2012	1.475	%	$	311.2

Vested at March 31, 2012	2.925	%	$	259.8

The Company recognizes compensation expense ratably over the four year vesting period. Non-cash compensation expense (recorded in general and administrative expense) related to the three months ended March 31, 2012 and 2011 was $153 and $58. The Company recorded non-cash compensation expense of $582 in the three months ended March 31, 2011 related to 2010 and 2009. As of March 31, 2012, the unrecognized non-cash compensation expense for the remaining vesting period is $1,167. Incremental non-cash compensation expense will be recorded over the remaining expected weighted average vesting period of 1.9 years.

10. COMMITMENTS AND CONTINGENCIES

Contractual Commitments—The Company leases office space in Dallas, Texas, Atlanta, Georgia, Houston, Texas and Grand Prairie, Texas, and has determined that its leases are classified as operating leases.

Total rent expense related to operating leases was $137 and $55 for the three month periods ended March 31, 2012 and 2011, and was recorded within general and administrative.

Legal Proceedings—The Company is involved in various legal and administrative proceedings in the normal course of business, the ultimate resolution of which, in the opinion of management, should not have a material effect on the Company's financial condition, results of operations, or liquidity.

F-17

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

11. RELATED-PARTY TRANSACTIONS

Promissory Notes Payable to Sponsors—The Company has entered into promissory note agreements with its owners in conjunction with the acquisition of Grand River Gathering. (See Note 7)

Electricity Management Services Agreement—The Company entered into a consulting arrangement with Equipower Resources Corp. ("Equipower"), an affiliate of Energy Capital Partners, whereby Equipower assists the Company with managing its electricity price risk. During the three month periods ended March 31, 2012 and 2011, the Company paid Equipower $44 and zero for such services.

Diligence Expenses—In the past, the Sponsors reimbursed the Company for transactional due diligence expenses related to proposed transactions that were not completed. As of March 31, 2012 and December 31, 2011, the Company had a receivable from the Sponsors of $0 and $1,309, respectively, for similar expenses. During the three months ended March 31, 2012 the company was reimbursed $319 while $990 was not paid.

Transition Services Agreement—The Company executed a transition services agreement with TCEH effective September 3, 2009. The services provided to the Company by TCEH included the temporary use of TCEH office space; ongoing utilization of accounting and financial reporting services support; general support regarding any administration of Consolidated Omnibus Budget Reconciliation Act (COBRA) health benefits; general information technology support to manage data files, addresses, network connectivity, etc.; and use of computers, right-of-way services, and public relation services. The costs and rates charged to the Company by TCEH related to each service were negotiated and mutually agreed to by both parties. The termination date related to each service provided under the agreement varies with the option to extend certain services if deemed necessary and agreed to by both parties. The extension periods are in three-month intervals beginning January 1, 2010, and are limited to 18 months in total. As of March 31, 2012, the only services provided under the agreement that remain relate to the right-of-way services. The amounts charged to the Company through the transition services agreement for the three month periods ended March 31, 2012 and 2011, were $8 and $14.

12. CONCENTRATIONS OF RISK

Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and accounts receivable. The Company maintains its cash in bank deposit accounts that, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts and does not believe it is exposed to any significant risk.

Accounts receivable are primarily from natural gas producers shipping natural gas and from natural gas marketers' purchase and sale of natural gas. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that the Company's customers may be similarly affected by changes in economic, industry or other conditions. The Company monitors the creditworthiness of all of its counterparties. The Company generally requires letters of credit for receivables from customers that are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated.

For the three month periods ended March 31, 2012 and 2011, the Company had three customers (each comprising over 10% of total revenue) that accounted for approximately 65% and 58% of total

F-18

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

12. CONCENTRATIONS OF RISK (Continued)

gas revenue. The total accounts receivable from these customers accounted for approximately 60% and 51% of accounts receivable as of March 31, 2012 and December 31, 2011.

The following tables summarize concentrations of revenue in excess of 10% of total revenue for the three month periods ended March 31, 2012 and 2011, and accounts receivable in excess of 10% of accounts receivable as of March 31, 2012 and December 31, 2011:

Production Company

*Revenue:*
Customer A	31	%	0	%
Customer B	18		19
Customer C	16		39
*Accounts receivable:*
Customer A	39	%	0	%
Customer B	11		8
Customer C	10		43

******

F-19

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers of Summit Midstream Partners, LLC
Dallas, Texas

We have audited the accompanying consolidated balance sheets of Summit Midstream Partners, LLC and subsidiaries (the "Company") as of December 31, 2011 and 2010 (Successor), and the related consolidated statements of operations, membership interests, and cash flows for the years ended December 31, 2011 and 2010 (Successor), for the period from September 3, 2009 (Inception) through December 31, 2009 (Successor) and for the period from January 1, 2009 through September 3, 2009 (Predecessor). These financial statements are the responsibility of the Company'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). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2011 and 2010, (Successor) and for the years ended December 31, 2011 and 2010 (Successor), for the period from September 3, 2009 (Inception) through December 31, 2009 (Successor), and for the period from January 1, 2009 through September 3, 2009 (Predecessor), in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 4 to the consolidated financial statements, the Company acquired Grand River Gathering Company, LLC on October 27, 2011. Also, as discussed in Note 3 to the consolidated financial statements, the Company acquired a controlling interest in DFW Midstream Services LLC on September 3, 2009.

/s/ Deloitte & Touche LLP

Dallas, Texas
May 11, 2012

F-20

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR)

Dollars in Thousands

	2011 (Successor)		2010 (Successor)

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	15,462	$	9,421
Accounts receivable		27,476		10,238
Other assets		1,966		217

Total current assets		44,904		19,876
PROPERTY, PLANT, AND EQUIPMENT—Net (Note 6)		642,552		277,765
OTHER NONCURRENT ASSETS		4,979		175
INTANGIBLE ASSETS—Net (Note 5)
Favorable contract		21,673		23,391
Contracts		279,588		—
Rights-of-way		32,802		18,888

TOTAL ASSETS	$	1,026,498	$	340,095

LIABILITIES AND MEMBERSHIP INTERESTS
CURRENT LIABILITIES:
Accounts payable—trade	$	22,420	$	18,168
Other current liabilities		4,971		4,203

Total current liabilities		27,391		22,371
PROMISSORY NOTES PAYABLE TO SPONSORS (Note 8)		202,893		—
REVOLVING CREDIT FACILITY (Note 7)		147,000		—
NONCURRENT LIABILITIES—Net (Note 5)		8,944		10,354

Total liabilities		386,228		32,725

COMMITMENTS AND CONTINGENCIES (Note 11)
MEMBERSHIP INTERESTS (Note 10):
Summit membership interests		640,270		307,370
Noncontrolling interest in subsidiary		—		—

Total membership interests		640,270		307,370

TOTAL LIABILITIES AND MEMBERSHIP INTERESTS	$	1,026,498	$	340,095

The accompanying notes are an integral part of these consolidated financial statements.

F-21

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

Dollars in Thousands



	2011 (Successor)			2010 (Successor)			Period from September 3, 2009 (Inception) through December 31, 2009 (Successor)			Period from January 1, 2009 through September 3, 2009 (Predecessor)
REVENUES:
Gathering services and other fees	$	91,421		$	29,358		$	1,714		$	1,910
Natural gas and condensate sales		12,439			2,533			—			—
Amortization of favorable and unfavorable contracts		(308	)		(215	)		19			—
									��
Total revenues		103,552			31,676			1,733			1,910

COSTS AND EXPENSES:
Operation and maintenance		29,855			9,503			1,147			1,010
General and administrative		17,476			10,035			2,939			600
Transaction costs		3,166			—			3,921			—
Depreciation and amortization		11,915			3,874			343			882

Total costs and expenses		62,412			23,412			8,350			2,492
OTHER INCOME		12			32			18			—
INTEREST EXPENSE		(1,029	)		—			—			—
AFFILIATED INTEREST EXPENSE		(2,025	)		—			—			(247	)

INCOME (LOSS) BEFORE INCOME TAXES		38,098			8,296			(6,599	)		(829	)
INCOME TAX EXPENSE		(695	)		(124	)		(7	)		(8	)

NET INCOME (LOSS)		37,403			8,172			(6,606	)		(837	)
NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST		—			78			(400	)		—

NET INCOME (LOSS) ATTRIBUTABLE TO SUMMIT MIDSTREAM PARTNERS, LLC	$	37,403		$	8,094		$	(6,206	)	$	(837	)

Supplemental unaudited pro forma earnings per common unit (See Note 1)	$

The accompanying notes are an integral part of these consolidated financial statements.

F-22

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBERSHIP INTERESTS

Dollars in Thousands

Predecessor	Membership Interest

BALANCE—January 1, 2009	$	135
Conversion of TCEH advances to membership interest		64,870
Net loss		(837	)

BALANCE—September 3, 2009	$	64,168

Successor	Summit Midstream Member Interests			Noncontrolling Interest			Total

BALANCE—September 3, 2009 (inception)	$	—		$	—		$	—
Contribution from Sponsor at formation		107,000			—			107,000
Contributions		27,871			15,417			43,288
Noncash contribution		1,603			—			1,603
Distribution of cash to TCEH at DFW Transaction		—			(40,186	)		(40,186	)
Fair value of property contributed by TCEH at DFW Transaction		—			79,967			79,967
Net loss		(6,206	)		(400	)		(6,606	)

BALANCE—December 31, 2009		130,268			54,798			185,066
Contributions		194,134			10,720			204,854
Purchase of interest in subsidiary from noncontrolling interest		(25,126	)		(65,596	)		(90,722	)
Net income		8,094			78			8,172

BALANCE—December 31, 2010		307,370			—			307,370
Contributions from Sponsors		425,000			—			425,000
Distribution of cash to Sponsor		(132,943	)		—			(132,943	)
Class B unit based compensation		3,440			—			3,440
Net income		37,403			—			37,403

BALANCE—December 31, 2011	$	640,270		$	—		$	640,270

The accompanying notes are an integral part of these consolidated financial statements.

F-23

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

Dollars in Thousands



	2011 (Successor)			2010 (Successor)			Period from September 3, 2009 (Inception) through December 31, 2009 (Successor)			Period from January 1, 2009 through September 3, 2009 (Predecessor)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	37,403		$	8,172		$	(6,606	)	$	(837	)
Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities:
Depreciation and amortization		11,915			3,875			343			882
Amortization of favorable and unfavorable contracts		308			215			(19	)		—
Amortization of deferred loan costs		560			—			—			—
Pay in kind interest on promissory notes payable to Sponsors		2,025
Unit based compensation expense		3,440			—			—			—
Changes in operating assets and liabilities:
Accounts receivable		(17,238	)		(8,865	)		(1,373	)		550
Accounts payable—trade		2,468			4,209			2,440			—
Other assets		(1,707	)		125			(517	)		—
Other current liabilities		768			1,822			(500	)		—

Cash provided by (used in) operating activities		39,942			9,553			(6,232	)		595

CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition of Chesapeake assets		—			—			(44,896	)		—
Acquisition of Grand River Gathering		(589,462	)		—			—			—
Capital expenditures		(78,248	)		(153,719	)		(19,519	)		(40,777	)

Cash used in investing activities		(667,710	)		(153,719	)		(64,415	)		(40,777	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Contribution from Sponsor at formation		—			—			107,000			—
Contributions from Sponsors		425,000			194,134			27,871			—
Distribution to Sponsor		(132,943	)		—			—			—
Contributions from noncontrolling interest		—			10,720			15,417
Distribution to noncontrolling interest at DFW Transaction		—			—			(40,186	)		—
Promissory notes payable to Sponsors		200,000			—			—			—
Borrowings under revolving credit facility		147,000			—			—			—
Purchase of interest in subsidiary from noncontrolling interest		—			(90,722	)		—			—
Deferred loan costs and initial public offering costs		(5,248	)		—			—			—
Advances from TCEH		—			—			—			40,182

Cash provided by financing activities		633,809			114,132			110,102			40,182

NET CHANGE IN CASH AND CASH EQUIVALENTS		6,041			(30,034	)		39,455			—
CASH AND CASH EQUIVALENTS—Beginning of period		9,421			39,455			—			—

CASH AND CASH EQUIVALENTS—End of period	$	15,462		$	9,421		$	39,455		$	—

SUPPLEMENTAL SCHEDULE OF INVESTING AND FINANCING ACTIVITIES:
Cash interest paid	$	2,463		$	—		$	—		$	—
Capitalized interest		(3,362	)		—			—			—

Interest paid (net of capitalized interest)	$	(899	)	$	—		$	—		$	—

Cash paid for taxes	$	223		$	10		$	—		$	—

F-24

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)

Dollars in Thousands



	2011 (Successor)		2010 (Successor)		Period from September 3, 2009 (Inception) through December 31, 2009 (Successor)		Period from January 1, 2009 through September 3, 2009 (Predecessor)
SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Capital expenditures in accounts payable (period end accruals)	$	11,332	$	12,958	$	16,631	$	2,252

Pay in kind interest	$	2,893	$	—	$	—	$	—

Contribution from ECP	$	—	$	—	$	1,603	$	—

Conversion of TCEH advances to member interest	$	—	$	—	$	—	$	64,870

The accompanying notes are an integral part of these consolidated financial statements.

F-25

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

1. ORGANIZATION AND BUSINESS OPERATIONS

Organization—Summit Midstream Partners, LLC (the "Company" or "Summit Midstream"), a Delaware limited liability company, was formed and began operations on September 3, 2009 (inception). The Company's business strategy is to own and operate a portfolio of midstream energy infrastructure assets that are strategically located in the core areas of unconventional resource basins in North America. Through August 17, 2011, the Company was wholly-owned by Energy Capital Partners II, LP and its parallel and co-investment funds (collectively, "Energy Capital Partners" or "Sponsor"). On August 17, 2011, Energy Capital Partners sold an 11.25% membership interest in the Company to a subsidiary of GE Energy Financial Services, Inc. ("GE Energy Financial Services" or "Sponsor", collectively with Energy Capital Partners, "Sponsors"). Subsequent to the sale of this noncontrolling interest to GE Energy Financial Services, Energy Capital Partners continues to control the activities of Summit Midstream through its representation on the Company's board of managers. Certain members of the Summit Midstream management hold ownership interests in the form of Class B Units in Summit Midstream through their ownership in Summit Midstream Management, LLC.

Concurrent with the Company's formation on September 3, 2009, the Company acquired a controlling interest in DFW Midstream Services LLC ("DFW Midstream"), and accordingly, the DFW Midstream Limited Liability Company Agreement was amended and restated to effect among other things (i) the continuation of Texas Competitive Electric Holdings Company LLC ("TCEH") as a Class A Member, (ii) the admission of Summit Midstream as a Class A Member, (iii) the admission of DFW Midstream Management LLC as the Class B Member, and (iv) the continuation of DFW Midstream as a Delaware limited liability company. The acquisition of a controlling interest in DFW Midstream by Summit Midstream was accounted for under the acquisition method of accounting. Summit Midstream's consolidated financial statements reflect DFW Midstream's operations for all periods presented.

On June 2, 2010, Summit Midstream purchased all of TCEH's remaining membership interests in DFW Midstream. The transaction was completed on June 18, 2010. The purchase of the remaining noncontrolling interest in DFW Midstream was accounted for as an equity transaction (see Note 10).

On October 4, 2011 the Company entered into a purchase and sale agreement with Encana Oil & Gas (USA) Inc., a subsidiary of Encana Corporation ("Encana"), to acquire certain natural gas gathering pipeline, dehydration and compression assets in western Colorado for $590 million. These assets gather production from the Mamm Creek, Orchard, and South Parachute fields in the area around Rifle, Colorado. The assets gather natural gas under long-term contracts ranging from 10-25 years. In addition to the purchase, the Company has a contractual relationship with Encana related to the development of midstream infrastructure to support Encana's emerging Mancos Shale and Niobrara development. The transaction closed on October 27, 2011 with an effective date of October 1, 2011. The assets are owned by Grand River Gathering, LLC, a wholly owned subsidiary of the Company ("Grand River Gathering"). The transaction was funded through an equity contribution and an aggregate of $200 million in promissory notes from the Sponsors.

F-26

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

1. ORGANIZATION AND BUSINESS OPERATIONS (Continued)

Business Operations—Summit Midstream's two operating subsidiaries are DFW Midstream and Grand River Gathering. Both are midstream energy companies focused on the development, construction and operation of natural gas gathering systems. DFW Midstream's gathering system is located in the core of the Barnett Shale located in the Fort Worth basin in Texas. Grand River Gathering's gathering system is located in the Piceance Basin, which includes the Mesaverde, Mancos and Niobrara Shale formations in western Colorado.

Basis of Presentation—The consolidated financial statements include the assets, liabilities, and results of operations of the Company and its wholly-owned subsidiaries Summit Midstream Holdings, LLC ("Holdings"), Grand River Gathering and DFW Midstream, and have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The consolidated financial statements for the years ended December 31, 2011 and 2010, and for the period from September 3, 2009 (inception) through December 31, 2009, reflect the application of purchase accounting related to the acquisition of a controlling interest in DFW Midstream by Summit Midstream on September 3, 2009. The consolidated financial statements also include the operations of Grand River Gathering upon the closing of the transaction on October 27, 2011.

The consolidated financial statements provided for the period from January 1, 2009 through September 3, 2009, include only the operations of DFW Midstream which is the predecessor of Summit Midstream. These financial statements represent the results of operations, changes in membership interest and cash flows of DFW Midstream and have been carved out of the accounting records maintained by Energy Future Holdings Corp. and its subsidiaries ("Energy Future Holdings"). Historically, Energy Future Holdings did not allocate general and administrative ("G&A") expenses to DFW Midstream for any centralized finance and administrative costs. Accordingly, the financial statements for the period from January 1, 2009 through September 3, 2009 (inception) include an estimate of G&A for the period of $588 based on the level of significance of DFW Midstream to Energy Future Holdings, the number of employees directly involved in DFW Midstream and considering the capital intensive nature of the activities of DFW Midstream during this period. The estimate of G&A expenses was predominantly related to rent, insurance and other employee related expenses. Because of the nature of these carved-out financial statements, the intercompany advances from Energy Future Holdings were reported within an intercompany advances account, and immediately prior to the acquisition, were converted to membership interest.

All intercompany transactions have been eliminated upon consolidation. Subsequent events have been evaluated through May 11, 2012, the date these financial statements were available to be issued.

The Company's operations are organized into a single business segment, the assets of which consist of natural gas gathering systems and related plant and equipment.

The Company is the predecessor for accounting purposes of Summit Midstream Partners, LP ("SMLP") who submitted a registration statement for its initial public offering of common units on a confidential basis.

F-27

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

1. ORGANIZATION AND BUSINESS OPERATIONS (Continued)

Supplemental Unaudited Pro Forma Information—Staff Accounting Bulletin 1.B.3 requires that certain distributions to owners prior to or coincident with an initial public offering be considered as distributions in contemplation of that offering. Upon completion of this offering, SMLP intends to distribute approximately $ million in cash to the Sponsors. Supplemental unaudited basic and diluted pro forma earnings per common unit for Summit Midstream Partners, LP for the year ended December 31, 2011 assumed general partner units, subordinated units and common units were outstanding in the period. The common units consists of common units issued to the Sponsors plus an additional units, which is the number of common units that we would have been required to issue to fund the $ million distribution of net proceeds to the Sponsors. The number of common units that SMLP would have been required to issue to fund the $ million distribution was calculated as $ million minus the Company's net earnings of $37.4 million for the year ended December 31, 2011 divided by an issue price per unit of $ , which is the initial public offering price of $ per common unit less the estimated underwriting discounts, structuring fee and offering expenses. There were no potential common units outstanding to be considered in the pro forma diluted earnings per unit calculation.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates—The consolidated financial statements have been prepared in conformity with GAAP, which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates, the reported amounts of revenue and expense, including fair value measurements, and disclosure of contingencies. Although management believes these estimates are reasonable, actual results could differ from its estimates.

Cash and Cash Equivalents—Cash and cash equivalents include temporary cash investments with original maturities of three months or less.

Accounts Receivable—Accounts receivable relate to gathering and other services provided to independent natural gas producer customers. Accounts receivable included in the balance sheets are net of an allowance for doubtful accounts. At December 31, 2011 and 2010, the Company recorded no allowance for doubtful accounts. The Company did not experience non-payment for services during any period presented.

Intangible Assets and Liabilities—Intangible assets and unfavorable contracts consisting of favorable and unfavorable gas gathering contracts are amortized on a units-of-production basis over the life of the contract, which is the period over which the contracts are expected to contribute directly or indirectly to the Company's future cash flows. The favorable and unfavorable contracts relate to gas gathering contracts that were deemed to be above or below market at the acquisition of DFW Midstream. The contract lengths range from 10 years to 20 years.

F-28

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Intangible assets consisting of contract values related to the Grand River Gathering gas gathering agreements are amortized over the period of economic benefit based upon the expected revenues over the life of the contract, which range from 10 years to 25 years.

Right-of-way intangible assets associated with city easements and easements granted within existing rights-of-way are amortized over the shorter of the contractual term of the rights-of-way, ranging from 20 years to 30 years, or the estimated useful life of the gathering system, which is 30 years.

Property, Plant, and Equipment—Property, plant, and equipment are recorded at historical cost of construction or, upon acquisition, the fair value of the assets acquired. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred. Expenditures to extend the useful lives of the assets or enhance their productivity or efficiency from their original design are capitalized over the expected remaining period of use. The carrying value of the assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. Sales or retirements of assets, along with the related accumulated depreciation, are removed from the accounts and any gain or loss on disposition is included in statement of operations. Costs related to projects during construction, including interest on funds borrowed to finance the construction of facilities, are capitalized as construction in progress.

Depreciation of property, plant, and equipment is recorded on a straight-line basis over the estimated useful lives. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets.

Impairment of Long-Lived Assets—Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. Assets are tested 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 cash flows expected to result from the use and eventual disposition of the long-lived asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is determined using an income approach whereby the expected future cash flows are discounted using a rate management believes a market participant would assume is reflective of the risk associated with achieving the underlying cash flows. The Company did not recognize any impairment of long-lived assets during any period presented.

Other Noncurrent Assets—Other noncurrent assets primarily consist of external costs incurred in connection with the closing of the Company's revolving credit facility and costs incurred related to the Company's contemplated initial public offering. Deferred loan costs are capitalized and amortized over the life of the related agreement. Amortization of deferred loan costs is included in interest expense in the statement of operations.

F-29

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Asset Retirement Obligations—Accounting standards related to asset retirement obligations require the Company to evaluate whether any future asset retirement obligations exist as of December 31, 2011 and 2010, and whether the expected retirement date of the related costs of retirement can be estimated. We have concluded that our natural gas gathering system assets, which include pipelines, compression facilities and dehydration facilities, have an indeterminate life because they are owned and will operate for an indeterminate future period when properly maintained. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified. The Company did not provide any asset retirement obligations as of December 31, 2011 and December 31, 2010 because it does not have sufficient information to reasonably estimate such obligations, and the Company has no current intention of discontinuing use of any significant assets.

Commitments and Contingencies—The consolidated financial results of the Company may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. See Note 8 for a discussion of commitments and contingencies.

Environmental Matters—The operations of the Company and the Predecessor are subject to various federal, state and local laws and regulations relating to the protection of the environment. Although the Company believes that it is in compliance with applicable environmental regulations, the risk of costs and liabilities are inherent in pipeline ownership and operation, and there can be no assurances that significant costs and liabilities will not be incurred by the Company. Management is not aware of any contingent liabilities that currently exist with respect to environmental matters.

Income Taxes—Provision for income taxes is attributable to the Company's state tax obligations under the gross margin tax enacted by the State of Texas. Since the Company is structured as a partnership for federal income tax purposes, the Company is not subject to federal income taxes. As a result, the Company's members are individually responsible for paying federal income taxes on their

F-30

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

share of the Company's taxable income. See Note 9 for additional information regarding the Company's income taxes.

Fair Value of Financial Instruments—The carrying amount of cash and cash equivalents, accounts receivable, and accounts payable approximates fair value due to their short-term maturities.

Comprehensive Income (Loss)—Comprehensive income (loss) is the same as net income (loss) for all periods presented.

Earnings Per Unit—Earnings per unit has not been presented because the Company's members hold interests and not units.

Recent Accounting Pronouncements—Accounting standard-setting organizations frequently issue new or revised accounting rules. The Company regularly reviews all new pronouncements to determine their impact, if any, on its consolidated financial statements. There are currently no recent pronouncements that have been issued that the Company believes will materially affect its consolidated financial statements.

3. PURCHASE OF CONTROLLING INTEREST IN DFW MIDSTREAM

On September 3, 2009, the Company acquired a controlling interest in DFW Midstream from TCEH (the "DFW Transaction"). At the date of the DFW Transaction, the Company received a capital contribution from Energy Capital Partners of $107,000 and contributed $85,082 to DFW Midstream in exchange for a 75% membership interest. Concurrently, DFW Midstream purchased certain natural gas gathering assets under construction located in the Barnett Shale from a division of Chesapeake Energy Corporation for $44,896, and a distribution of $40,186 was made by DFW Midstream to TCEH.

F-31

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

3. PURCHASE OF CONTROLLING INTEREST IN DFW MIDSTREAM (Continued)

The Company accounted for the DFW Transaction under the acquisition method of accounting, whereby the total purchase price of the DFW Transaction was allocated to DFW Midstream's identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values as of September 3, 2009. The intangible assets acquired were right-of-way easements (weighted average life of 28.6 years) and favorable gas gathering agreements (weighted average life of 18.7 years). The intangible liabilities acquired were unfavorable gas gathering agreements. The fair values were determined based upon assumptions related to future cash flows, discount rates, asset lives, and projected capital expenditures to complete DFW Midstream's gathering system. The purchase price was estimated by imputing the value of 100% of the membership interests in DFW Midstream based upon $85,082 in cash contributed by Summit Midstream in exchange for an economic interest in DFW Midstream equal to 70.5% of future distributions and the obligation to contribute 75% of the project completion budget. The purchase price was equal to the fair value of the net assets of DFW Midstream; thus, no goodwill was recorded.

Fair values of the assets acquired and liabilities assumed as of September 3, 2009 are as follows:


Purchase price assigned to DFW Midstream			$	124,863

Property, plant, and equipment	$	108,879
Favorable contracts		24,195
Rights-of-way		5,640
Other assets		793

Total assets acquired		139,507

Unfavorable contract		10,962
Other liabilities		3,682

Total liabilities assumed	$	14,644

Net identifiable assets acquired				124,863

Goodwill			$	—

In connection with the DFW Transaction, TCEH contributed assets consisting of property, plant and equipment related assets primarily under construction, gas gathering contracts and rights-of-way. The fair value of property, plant and equipment was determined utilizing the cost approach because of the early stage of construction or certain of the related assets having been recently purchased at the time of the DFW Transaction. The fair value of the gas gathering contracts was determined utilizing a discounted cash flow approach based upon the forecasted volumes under the applicable contract and the difference between the contractual and market rates for similar services in the area. The rights-of-way were valued based upon similar acreage and utilizing an assemblage factor for the contiguous easements acquired.

F-32

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

3. PURCHASE OF CONTROLLING INTEREST IN DFW MIDSTREAM (Continued)

The noncontrolling interest in DFW Midstream held by TCEH at September 3, 2009, was estimated based on TCEH's economic interest in DFW Midstream equal to 29.5% of future distributions and the obligation to contribute 25% of the capital expenditures in the project completion budget, and was adjusted to reflect the lack of control and lack of marketability that market participants would be expected to consider when estimating the fair value of the noncontrolling interest in DFW Midstream.

In connection with the DFW Transaction, the Company incurred $3,921 in transaction costs, which were expensed as incurred and are reported within transaction costs. Such costs include $1,075 paid to Energy Capital Partners Management II, LP, a related party; $1,103 paid to Energy Capital Partners Management LP, a related party; and $1,743 paid to third parties (of which $1,603 was paid by Energy Capital Partners on behalf of the Company) for strategic, advisory, management, legal, and consulting services. Transaction costs paid by Energy Capital Partners are presented as a noncash capital contribution.

4. ACQUISITION OF GRAND RIVER GATHERING

The Company completed the acquisition of Grand River Gathering from Encana for $590 million, effective October 1, 2011 (the "Grand River Transaction"). The Grand River Gathering natural gas midstream assets are located in the Piceance Basin. The acquired assets include approximately 260 miles of pipeline and 90,000 horsepower of compression facilities. These assets gather production from the Mamm Creek, Orchard, and South Parachute fields in the area around Rifle, Colorado. The assets gather natural gas under long-term contracts ranging from 10 years to 25 years (weighted average life of 12.8 years). In addition to the purchase, the Company has a contractual relationship with Encana related to the development of midstream infrastructure to support Encana's emerging Mancos Shale and Niobrara development.

The Grand River Transaction closed on October 27, 2011 with an effective date of October 1, 2011. The assets are owned by Grand River Gathering, LLC, a wholly-owned subsidiary of the Company. The Grand River Transaction was funded through an equity contribution of $410 million and promissory notes from the Sponsors totaling $200 million. For the period ended December 31, 2011, the Company recorded $12,824 of revenue and $2,111 of net income related to Grand River Gathering.

The Company accounted for the Grand River Transaction under the acquisition method of accounting, whereby the total purchase price of the Grand River Transaction was allocated to Grand River Gathering's identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values as of October 27, 2011. The intangible assets that were acquired are comprised gas gathering agreement contract values and right-of-way easements. The fair values were determined based upon assumptions related to future cash flows, discount rates, asset lives, and projected capital expenditures to complete Grand River Gathering's gathering system. The Company has not completed the final purchase price allocation to the assets acquired and liabilities assumed as of December 31,

F-33

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

4. ACQUISITION OF GRAND RIVER GATHERING (Continued)

2011, because the Company is waiting to receive certain information in order to complete its determination of the values of acquired assets under construction, the related impacts on the valuation of the customer contract intangible assets and the final settlement of the purchase price.

Fair values of the assets acquired and liabilities assumed as of October 27, 2011 are as follows:


Purchase price assigned to Grand River Gathering			$	590,000

Property, plant, and equipment	$	300,000
Gas gathering agreement contract intangibles		282,000
Rights-of-way		8,000

Total assets acquired		590,000

Noncurrent liabilities		—
Other liabilities		—

Total liabilities assumed	$	—

Net identifiable assets acquired				590,000

Goodwill			$	—

The Company determined that the purchase price was equal to the fair value of the net assets acquired; thus, no goodwill was recorded.

Unaudited Pro Forma Financial Information—The following unaudited pro forma financial information assumes that the Grand River Gathering acquisition occurred on January 1, 2010 and the DFW Midstream acquisition (see Note 3) occurred on January 1, 2009. Transaction costs of $3,160 related to the acquisition of Grand River Gathering have been adjusted and recorded in 2010 for the proforma information below. The unaudited pro forma information is not necessarily indicative of what the Company's financial position or results of operation would have been if the transactions had occurred on those dates, or what the Company's financial position or results from operations will be for any future periods.

	Year Ended December 31, 2011		Year Ended December 31, 2010		Year Ended December 31, 2009

Revenue	$	167,671	$	108,619	$	3,679
Net income (loss)	$	52,173	$	17,599	$	(1,338	)

Pro forma adjustments for the year ended December 31, 2011 consist of $64,119 of revenue and $11,610 of net income for January through October of 2011 and $76,943 of revenue and $12,665 for the year ended December 31, 2010 related to Grand River Gathering assuming the acquisition date was January 1, 2010. These pro forma adjustments were derived by annualizing the actual operating results for Grand River Gathering that we recorded for the two month period from November 1, 2011 through

F-34

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

4. ACQUISITION OF GRAND RIVER GATHERING (Continued)

December 31, 2011. The transaction costs of $3,160 have been removed from the year ended December 31, 2011 and reflected in the year ended December 31, 2010. Pro forma adjustments for the year ended December 31, 2009 represent $39 of revenue and $654 of depreciation related to DFW Midstream assuming the DFW Transaction was effective January 1, 2009.

5. IDENTIFIABLE INTANGIBLE ASSETS AND NONCURRENT LIABILITY

The Company accounted for the DFW Transaction and the Grand River Transaction under the acquisition method of accounting and identified separately identifiable intangible assets and a noncurrent liability. Identifiable intangible assets and a noncurrent liability, which are subject to amortization as of December 31, 2011 and 2010, are composed of the following:

2011		Gross Carrying Amount		Accumulated Amortization			Net

Favorable gas gathering contracts	18.7	$	24,195	$	(2,522	)	$	21,673
Contract intangibles	12.4		282,000		(2,412	)		279,588
Rights-of-way	28.3		34,343		(1,541	)		32,802

Total amortizable intangible assets		$	340,538	$	(6,475	)	$	334,063

Unfavorable contract	10	$	10,962	$	(2,018	)	$	8,944

2010		Gross Carrying Amount		Accumulated Amortization			Net

Favorable gas gathering contracts	18.7	$	24,195	$	(804	)	$	23,391
Rights-of-way—city easements	28.3		19,521		(633	)		18,888

Total amortizable intangible assets		$	43,716	$	(1,437	)	$	42,279

Total amortizable noncurrent liability	10	$	10,962	$	(608	)	$	10,354

Amortization expense of $1,718, $764, $40, and $0 for the years ended December 31, 2011 and 2010, the period from September 3, 2009 (inception) through December 31, 2009, and the period from January 1, 2009 through September 3, 2009, respectively, related to the favorable gas gathering contract intangible assets was recorded within revenue. The favorable contract relates to a gas gathering contract that was deemed to be above market upon the acquisition of DFW Midstream. The favorable contract intangible assets are amortized on a units-of-production basis over their estimated useful lives, which is the period over which the assets are expected to contribute directly or indirectly to the Company's future cash flows.

Amortization expense of $2,412 for the year ended December 31, 2011 related to the intangible contract values of the gas gathering agreements at Grand River Gathering was recorded and is included in the depreciation and amortization expense in the statement of operations. The intangible asset

F-35

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

5. IDENTIFIABLE INTANGIBLE ASSETS AND NONCURRENT LIABILITY (Continued)

contract values are amortized over the period of economic benefit based upon the expected revenues over the life of the contract.

Amortization expense of $908, $519, $114, and $0 for the years ended December 31, 2011 and 2010, the period from September 3, 2009 (inception) through December 31, 2009, and the period from January 1, 2009 through September 3, 2009, respectively, related to rights-of-way associated with city easements and easements granted within existing rights-of-way was recorded within depreciation and amortization expense over the shorter of the contractual term of the rights-of-way, ranging from 20 to 30 years, or the estimated useful life of the gathering system, which is 30 years.

The unfavorable contract included within noncurrent liability relates to an unfavorable gas gathering contract that was deemed to be below market upon the acquisition of DFW Midstream. Amortization related to the unfavorable gas gathering contract was $1,410, $549, $60, and $0 for the years ended December 31, 2011 and 2010, the period from September 3, 2009 (inception) through December 31, 2009, and the period from January 1, 2009 through September 3, 2009, respectively, and was recorded within revenue. The unfavorable contract is amortized on a units-of-production basis over its estimated useful life, which is the period over which the liability is expected to contribute directly or indirectly to the Company's future cash flows.

The estimated aggregate amortization of intangible assets and a noncurrent liability for each of the five succeeding fiscal years from December 31, 2011 is as follows:

Years Ending December 31,	Intangible Assets		Unfavorable Liability

2012	$	18,373	$	1,333
2013		21,465		1,441
2014		24,705		1,549
2015		28,102		1,650
2016		29,690		1,571

There are no indefinite-lived intangible assets recorded as of December 31, 2011 or 2010.

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SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

6. PROPERTY, PLANT, AND EQUIPMENT—NET

Net property, plant, and equipment as of December 31, 2011 and 2010, is composed of the following:

		2011 (Successor)			2010 (Successor)

Gas gathering system	30	$	335,083		$	107,229
Compressor stations and compression equipment	30		165,600			55,436
Other	4-15		2,071			624

Total			502,754			163,289
Less accumulated depreciation			(12,180	)		(3,585	)

Net of accumulated depreciation			490,574			159,705
Construction in progress			151,978			118,061

Property, plant, and equipment—net		$	642,552		$	277,765

Depreciation expense related to property, plant, and equipment was $8,595, $3,355, $230, and $882 for the years ended December 31, 2011 and 2010, the period from September 3, 2009 (inception) through December 31, 2009, and the period from January 1, 2009 through September 3, 2009, respectively. The Company capitalized interest totaling $3,362 during the year ended December 31, 2011 and zero in any other period.

7. REVOLVING CREDIT FACILITY

On May 26, 2011, Holdings closed a senior secured revolving credit facility with total commitments of $285 million. The revolving credit facility, which matures in May 2016, contains a $150 million accordion provision that enables Holdings to increase the total size of the facility any time prior to maturity. The revolving credit facility allows for revolving loans, letters of credit and swingline loans. The revolving credit facility is secured by the membership interests of Holdings and DFW Midstream and substantially all of Holdings' and DFW Midstream's assets and is guaranteed by Holdings' subsidiaries. Borrowings under the revolving credit facility bear interest at London Interbank Offered Rate ("LIBOR") plus an applicable margin or a base rate, as defined in the credit agreement. Under the terms of the revolving credit facility, the applicable margin under LIBOR borrowings was 2.50% at December 31, 2011. As of December 31, 2011, availability under the revolving credit facility totaled $138 million. The unused portion of the revolving credit facility is subject to a commitment fee of 0.50%. The weighted-average interest rate as of December 31, 2011 was 2.88%.

The revolving credit facility requires Holdings to maintain a ratio of consolidated trailing 12-month EBITDA to net interest expense of not less than 2.5 to 1.0 (as defined in the credit agreement) 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 1.0 for up to six months following certain acquisitions (as defined in the credit agreement). As of December 31, 2011, Holdings was in compliance with all applicable covenants.

F-37

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

7. REVOLVING CREDIT FACILITY (Continued)

The revolving credit facility contains restrictive covenants that prohibit the declaration or payment of distributions by Holdings if a default then exists or would result therefrom, and otherwise limits the amount of distributions Holdings can make. An event of default may result in the acceleration of Holdings' repayment of outstanding borrowings under the revolving credit facility, the termination of the revolving credit facility and foreclosure on collateral. Upon closing of the facility, the Company made a distribution of $132.9 million to Energy Capital Partners. As of December 31, 2011, there was $147 million outstanding under the facility.

On May 7, 2012, Holdings closed on an amendment and restatement of its revolving credit facility, which expanded its borrowing capacity to $550 million from $285 million. Upon closing of the senior secured amended and restated revolving credit facility, the Company contributed its assets and membership interests in Grand River Gathering to Holdings and Holdings borrowed $163 million under the facility. As of May 11, 2012, we had $307 million of indebtedness under our revolving credit facility. Holdings utilized $160 million of the borrowings at closing to partially repay the promissory notes payable to Sponsors. The amended and restated credit facility is secured by the membership interests of Holdings, DFW Midstream and Grand River Gathering and substantially all of Holdings', DFW Midstream's and Grand River Gathering's assets and is guaranteed by Holdings' subsidiaries. The amended and restated revolving credit facility contains affirmative and negative covenants customary for credit facilities of this size and nature, that, among other things, limit or restrict the ability to incur additional debt, make investments, engage in certain mergers, consolidations, acquisitions or sales of assets, enter into swap agreements and power purchase agreements and enter into leases that would cumulatively obligate payments in excess of $30 million over any 12-month period. The interest costs, other fees and financial covenants of the amended and restated revolving credit facility are consistent with the May 2011 revolving credit facility. The amended and restated revolving credit facility matures in May 2016.

8. PROMISSORY NOTES PAYABLE TO SPONSORS

In conjunction with the purchase of Grand River Gathering, the Company executed promissory notes, on an unsecured basis, with its Sponsors. The notes totaled $200 million, mature on October 27, 2013 and have an 8% interest rate. The Company has the option to elect to pay the interest in kind and the Company made this election for all interest due as of December 31, 2011. The amount of interest paid in kind and accrued to the balance of the notes as December 31, 2011 is $2,893, resulting in $202,893 as the amount outstanding on the note as of December 31, 2011. During 2011, the Company capitalized $868 of the $2,893 interest expense related to costs incurred on capital projects under construction. As of December 31, 2011, the aggregate carrying value of these notes approximated the fair value. On May 7, 2012, the Company amended and restated its revolving credit facility. On May 8, 2012, the Company borrowed $163 million under the amended and restated revolving credit facility and used the same borrowings to prepay $160 million of the promissory notes payable to

F-38

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

8. PROMISSORY NOTES PAYABLE TO SPONSORS (Continued)

Sponsors. As of May 11, 2012, the balance under the promissory notes payable to Sponsors was $48,695.

9. INCOME TAXES

In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax (i.e., the Texas Margin Tax), including nontaxable entities such as limited liability companies, limited partnerships, and limited liability partnerships. The tax is assessed on the Texas-sourced taxable margin, which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the Texas Margin Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. The income tax provision recorded in operations associated with the Texas Margin Tax was $695, $124, $7, and $8, for the years ended December 31, 2011 and 2010, and for the period from September 3, 2009 (inception) through December 31, 2009, and the period from January 1, 2009 through September 3, 2009, respectively.

10. MEMBERSHIP INTERESTS

As described in Note 1, Summit Midstream is controlled by Energy Capital Partners through Energy Capital Partners' ownership of Class A membership interests in the Company. On August 17, 2011, Energy Capital Partners sold an 11.25% membership interest in the Company to GE Energy Financial Services, therefore as of December 31, 2011 Energy Capital Partners holds an 88.75% interest and GE Energy Financial Services holds an 11.25% interest in Summit Midstream. As of December 31, 2010 and 2009, Energy Capital Partners held all of the Company's membership interests. Such membership interests gives the Sponsors the right to participate in distributions and to exercise the other rights or privileges available to each entity under the Company's Amended and Restated Limited Liability Operating Agreement (the "Summit LLC Agreement").

F-39

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

Contemporaneously with the formation of Summit Midstream and the execution of the Summit LLC Agreement at September 3, 2009, Class B membership interests (the "SMP Net Profits Interests") up to 7.5% of Summit Midstream's total membership interests were authorized and 2.85% were granted to certain members of Summit Midstream Management, LLC. SMP Net Profits Interests participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested SMP Net Profits Interests. The SMP Net Profits Interests are accounted for as compensatory awards. Additional SMP Net Profits Interests were granted on April 1, 2010, April 1, 2011, and October 18, 2011. All grants vest ratably over 5 years 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 Summit LLC Agreement). As of December 31, 2011, 5.855% of SMP Net Profits Interests had been granted, and no SMP Net Profits Interests had been forfeited.

During the year ended December 31, 2011, the Company, with assistance from a third-party valuation expert, determined the fair value of the SMP Net Profits Interests as of the respective grant dates for the grants made prior to that date. Therefore, the 2011 awards were valued contemporaneously within the year issued, and the 2009 and 2010 awards were valued retrospectively. The SMP Net Profits Interests were valued utilizing an option pricing method, which models the Class A and Class B membership interests as call options on the underlying equity value of Summit Midstream and considers the rights and preferences of each 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 the Company. We estimated the enterprise value utilizing a combination of the income and market approaches. The income approach utilized the discounted cash flow method, whereby we applied a discount rate to estimated future cash flows of the Company. Key inputs include forecasted gathering volumes, revenues and costs; unlevered equity betas of the Company's peer group; equity market risk premium; company-specific risk premium; and terminal growth rate. Under the market approach, trading multiples of the securities of publicly-traded peer companies were applied to the Company's estimated future cash flows.

Additional significant inputs used in the option pricing method for the SMP Net Profits Interests granted in each of the years designated below are as follows:



Length of holding period restriction (in years)	4.25		3.75		4.75		3.21
Discount for lack of marketability	34.8	%	30.9	%	29.6	%	33.1	%
Volatility	52.5	%	49.8	%	43.2	%	49.3	%

F-40

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

Information regarding the amount and grant-date fair value of the vested and nonvested SMP Net Profits Interests as of December 31, 2009, 2010, and 2011 is presented below.

			Weighted- Average Grant Date Fair Value (per 1.0% of SMP Net Profits Interests)

Nonvested at September 3, 2009	0.000	%
Granted	2.850	%	$	386.0
Vested	0.190	%	$	386.0

Nonvested at December 31, 2009	2.660	%	$	386.0

Vested at December 31, 2009	0.190	%	$	386.0

Nonvested at January 1, 2010	2.660	%	$	386.0
Granted	1.005	%	$	1,125.4
Vested	0.721	%	$	540.6

Nonvested at December 31, 2010	2.944	%	$	600.5

Vested at December 31, 2010	0.911	%	$	508.4

Nonvested at January 1, 2011	2.944	%	$	600.5
Granted	2.000	%	$	1,504.5
Vested	0.986	%	$	817.9

Nonvested at December 31, 2011	3.958	%	$	1,003

Vested at December 31, 2011	1.897	%	$	669.2

The Company recognizes compensation expense ratably over the five year vesting period. The Company recorded non-cash compensation expense (recorded in general and administrative expense) in 2011 of $1,269 which included $463 related to years prior to 2011. Incremental unit based compensation will be recorded over the remaining expected weighted average vesting period of 3.2 years. As of December 31, 2011, the unrecognized compensation expense for the remaining vesting period is $3,971.

In connection with the Company's formation and acquisition of DFW Midstream on September 3, 2009, Energy Capital Partners contributed $107,000 to the Company in order to initially capitalize the Company and fund the Company's investment in DFW Midstream. Energy Capital Partners contributed an additional $27,871 of capital to Summit Midstream through December 31, 2009. Energy Capital Partners made cash contributions of $194,134 to the Company for the year ended December 31, 2010, which were primarily used to fund ongoing capital expenditures of DFW Midstream and purchase the

F-41

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

remaining noncontrolling interest in DFW Midstream from TCEH on June 18, 2010, as discussed below.

In connection with the closing of the Company's revolving credit facility in May 2011, the Company distributed $132,943 to Energy Capital Partners.

Noncontrolling Interest in DFW Midstream—During the three years ended December 31, 2011, the Company has had several changes in membership interests related to the ownership of its consolidated subsidiary DFW Midstream as discussed further below. At December 31, 2011 and 2010, 100% of the Class A membership interests of DFW Midstream were held by Summit Midstream or its direct subsidiary, Holdings. Summit Midstream, through its subsidiary Holdings, as the sole Class A Member, holds units that represent membership interests, which give the holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under the DFW Midstream Amended and Restated Limited Liability Company Agreement and Contribution Agreement (collectively the "LLC Agreement"). The LLC Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that Class A Members will receive.

In accordance with the LLC Agreement, capital accounts are maintained for the members. The capital account provisions of the LLC Agreement incorporate principles established for U.S. federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in the Company's consolidated financial statements.

The LLC Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that Class A Members will receive. Prior to Summit's purchase of TCEH's remaining interest in DFW Midstream on June 18, 2010 (as discussed immediately below), Summit held a 75% interest and TCEH held a 25% Class A membership interest; however, distributions and allocations of income and loss are based on a sharing percentage as defined in the LLC Agreement resulting in an allocation or distribution on a basis of 70.5% and 29.5% for Summit and TCEH, respectively. Capital contributions required under the LLC Agreement are in proportion to the owners' respective percentage ownership interests.

In 2010, Summit Midstream and TCEH entered into a Membership Interest Purchase Agreement whereby Summit Midstream purchased all of TCEH's membership interests in DFW Midstream for cash consideration of $90,722. Amounts reported as noncontrolling interest relate to TCEH's ownership interests in DFW Midstream prior to June 18, 2010. The change in Summit Midstream's ownership interest in DFW Midstream resulted in a decrease in membership interest of $25,126 for the year ended December 31, 2010, as the cash consideration paid exceeded the carrying value of the noncontrolling interest at June 18, 2010.

Distributions and allocations of income and loss for the periods presented prior to June 18, 2010, are based upon a sharing percentage as defined in the Amended and Restated LLC Agreement of DFW Midstream resulting in an allocation or distribution on a basis of 70.5% and 29.5% for Summit

F-42

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

Midstream and TCEH, respectively. Net income (loss) of $78 and $(400) was allocated to TCEH, as the noncontrolling interest holder, based upon its ownership interests and profits and losses allocation for the year ended December 31, 2010, and for the period from September 3, 2009 (inception) through December 31, 2009, respectively.

TCEH funded capital contributions in the amount of $10,720 and $15,417 for the year ended December 31, 2010, and for the period from September 3, 2009 (inception) through December 31, 2009, respectively. Additionally, in connection with the Company's acquisition of DFW Midstream on September 3, 2009, DFW Midstream distributed $40,186 to TCEH as a return of capital.

Contemporaneously with the execution of the LLC Agreement on September 3, 2009, up to 5% of DFW Midstream's total membership interests were authorized for issuance as Class B membership interests (the "DFW Net Profits Interests) and an aggregate of 4.50% of DFW Net Profits Interests were granted to certain members of DFW Midstream Management LLC. DFW Net Profits Interests participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested DFW Net Profits Interests. The DFW Net Profits Interests are accounted for as compensatory awards. Additional DFW Net Profits Interests were granted on April 1, 2010 and July 28, 2010. All grants vest ratably over 4 years 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 LLC Agreement). As of December 31, 2011, 4.80% of DFW Net Profits Interests had been granted and 0.40% DFW Net Profits Interests had been forfeited.

During the year ended December 31, 2011, the Company, with assistance from a third-party valuation expert, determined the fair value of the DFW Net Profits Interests as of the respective grant dates for the grants made prior to that date. Therefore, the 2009 and 2010 awards were valued retrospectively. The DFW Net Profits Interests were valued utilizing an option pricing method, which models the Class A and Class B membership interests as call options on the underlying equity value of DFW Midstream and considers the rights and preferences of each 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 DFW Midstream. We estimated the enterprise value utilizing a combination of the income and market approaches. The income approach utilized the discounted cash flow method, whereby we applied a discount rate to estimated future cash flows of the 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 growth rate. Under the market approach, trading multiples of the securities of publicly-traded peer companies were applied to the DFW Midstream's estimated future cash flows.

F-43

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

Additional significant inputs used in the option pricing method for the DFW Net Profits Interests granted in each of the years designated below are as follows:



Length of holding period restriction (in years)	4.25		3.75		3.43
Discount for lack of marketability	34.8	%	30.9	%	35.9	%
Volatility	52.5	%	49.8	%	53.7	%

Information regarding the amount and grant-date fair value of the vested and nonvested DFW Net Profits Interests as of December 31, 2009, 2010, and 2011 is presented below.

			Weighted- Average Grant Date Fair Value (per 1.0% of DFW Net Profits Interests)

Nonvested at September 3, 2009	0.000	%
Granted	4.500	%	$	219.8
Vested	0.375	%	$	219.8

Nonvested at December 31, 2009	4.125	%	$	219.8

Vested at December 31, 2009	0.375	%	$	219.8

Nonvested at January 1, 2010	4.125	%	$	219.8
Granted	0.300	%	$	1,060.0
Vested	1.175	%	$	252.4
Forfeited	0.400	%	$	219.8

Nonvested at December 31, 2010	2.850	%	$	294.8

Vested at December 31, 2010	1.550	%	$	244.5

Nonvested at January 1, 2011	2.850	%	$	294.8
Granted	0.000	%	$	0.0
Vested	1.100	%	$	277.0

Nonvested at December 31, 2011	1.750	%	$	305.9

Vested at December 31, 2011	2.650	%	$	258.0

Forfeited at December 31, 2011	0.400	%	$	219.8

The Company recognizes compensation expense ratably over the four year vesting period. The Company recorded non-cash compensation expense (recorded in general and administrative expense) in 2011 of $2,171 which included $582 related to years prior to 2011. During the year ended

F-44

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

December 31, 2011, the Company modified the awards to remove a rate of return payout hurdle and as a result of the modification; the Company valued the Class B Units immediately prior to and following the modification to determine incremental compensation expense. The modification resulted in the immediate expense of $1,358 attributed to the previously vested Class B Units which is included in the $1,589 of compensation expense recorded during the year ended December 31, 2011. Incremental unit based compensation will be recorded over the remaining expected weighted average vesting period of 2.1 years. As of December 31, 2011, the unrecognized compensation expense for the remaining vesting period is $1,321.

Predecessor Membership Interests—Prior to the DFW Transaction, TCEH funded the Company's construction activities and working capital needs through intercompany loans or advances that accrued interest at an average rate of 4.29% for the predecessor period. Immediately prior to the DFW Transaction, the advances were converted to a membership interest.

11. COMMITMENTS AND CONTINGENCIES

Contractual Commitments—The Company leases office space for its headquarters in Dallas, Texas and for other offices in Atlanta, Georgia, Houston, Texas and Grand Prairie, Texas , and has determined that its leases are classified as operating leases. A schedule of future minimum lease payments for operating leases that had initial or remaining noncancelable lease terms in excess of one year as of December 31, 2011 is as follows:

	Operating Leases

2012	$	532
2013		534
2014		462
2015		338
2016		252

Total rent expense related to operating leases was $489, $212, $28, and $0 for the years ended December 31, 2011 and 2010, and for the period from September 3, 2009 (inception) to December 31, 2009, the period from January 1, 2009 through September 3, 2009, respectively, and was recorded within general and administrative.

F-45

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

12. RELATED-PARTY TRANSACTIONS

Transaction Costs—As discussed in Note 3, during 2009 the Company paid transaction costs of $1,075 and $1,103 to Energy Capital Partners Management II, LP and Energy Capital Partners Management, LP, respectively.

Diligence Expenses—The Sponsors agreed to reimburse the Company for previous transactional due diligence expenses related to proposed transactions that were not completed. As of December 31, 2011, the Company had a receivable from the Sponsors of $1,309 related to this previous agreement.

Transition Services Agreement—The Company executed a transition services agreement with TCEH effective September 3, 2009. The services provided to the Company by TCEH included the temporary use of TCEH office space; ongoing utilization of accounting and financial reporting services support; general support regarding any administration of Consolidated Omnibus Budget Reconciliation Act (COBRA) health benefits; general information technology support to manage data files, addresses, network connectivity, etc.; and use of computers, right-of-way services, and public relation services. The costs and rates charged to the Company by TCEH related to each service were negotiated and mutually agreed to by both parties. The termination date related to each service provided under the agreement varies with the option to extend certain services if deemed necessary and agreed to by both parties. The extension periods are in three-month intervals beginning January 1, 2010, and are limited to 18 months in total. As of December 31, 2011, the only services provided under the agreement that remain relate to the right-of-way services. The amounts charged to the Company through the transition services agreement for the years ended December 31, 2011 and 2010 and for the period from September 3, 2009 (inception) through December 31, 2009, were $39, $137 and $100, respectively.

Promissory Notes—The Company has entered into promissory note agreements with its owners in conjunction with the acquisition of Grand River Gathering. (See Note 8)

Electricity Management Services Agreement—The Company entered into a consulting arrangement with EquiPower Resources Corp. ("EquiPower"), an affiliate of Energy Capital Partners, whereby EquiPower assists the Company with managing its electricity price risk. During the years ended December 31, 2011 and 2010, the Company paid EquiPower $11 and zero for such services, respectively.

13. CONCENTRATIONS OF RISK

F-46

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

13. CONCENTRATIONS OF RISK (Continued)

customers may be similarly affected by changes in economic, industry or other conditions. The Company monitors the creditworthiness of all of its counterparties. The Company generally requires letters of credit for receivables from customers that are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated.

For the years ended December 31, 2011 and 2010, the Company had four customers (each comprising over 10% of total revenue) that accounted for approximately 73% and 88% of total gas revenue, respectively. The total accounts receivable from these customers accounted for approximately 66% and 95% of accounts receivable for the years ended December 31, 2011 and 2010, respectively.

The following tables summarize concentrations of revenue and accounts receivable in excess of 10% of total revenue and accounts receivable as of and for the years ended December 31, 2011 and 2010, for the period from September 3, 2009 (inception) through December 31, 2009 and for the period from January 1, 2009 through September 3, 2009, respectively:



Natural Gas Producers	2011 (Successor)			2010 (Successor)			Period from September 3, 2009 (Inception) through December 31, 2009 (Successor)			Period from January 1, 2009 through September 3, 2009 (Predecessor)
*Revenue*
Customer A		34	%		50	%		57	%		36	%
Customer B		10	%		11	%		37	%		60	%
Customer C		17	%		20	%
Customer D		12	%		7	%
*Accounts Receivable*
Customer A		43	%		53	%
Customer B		9	%		16	%
Customer C		8	%		14	%
Customer D		6	%		12	%

******

F-47

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers of Summit Midstream Partners, LLC as general partner of Summit Midstream Partners, LP
Dallas, Texas

We have audited the accompanying balance sheet of Summit Midstream Partners, LP (the "Partnership") as of May 10, 2012. The balance sheet is the responsibility of the Partnership's management. Our responsibility is to express an opinion on the balance sheet based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the balance sheet presents fairly, in all material respects, the financial position of the Partnership as of May 10, 2012, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Dallas, Texas
May 11, 2012

F-48

SUMMIT MIDSTREAM PARTNERS, LP

BALANCE SHEET

MAY 10, 2012


ASSETS
Current Assets
Cash	$	1,000

Total assets	$	1,000

LIABILITIES AND PARTNERS' EQUITY
COMMITMENTS AND CONTINGENCIES (Note 3)
Limited partner's interest	$	980
General partner's interest		20

TOTAL LIABILITIES AND PARTNERS' EQUITY	$	1,000

F-49

SUMMIT MIDSTREAM PARTNERS, LP

NOTE TO BALANCE SHEET

1. Nature of Operations

Summit Midstream Partners, LP (the "Partnership") is a Delaware limited partnership formed on May 1, 2012 to acquire certain assets and related contracts and agreements from the operating subsidiaries of Summit Midstream Partners, LLC. In order to simplify the Partnership's obligations under the laws of selected jurisdictions in which the Partnership will conduct business, the Partnership's activities will be conducted through a wholly owned limited liability company.

Summit Midstream GP, LLC, as general partner, contributed $20 and Summit Midstream Partners, LLC, as the organizational limited partner, contributed $980 to the Partnership on May 10, 2012.

2. Summary of Significant Accounting Policies

Basis of Presentation

This balance sheet has been prepared in accordance with accounting principles generally accepted in the United States of America. Separate statements of operations, membership interests, and cash flows have not been presented because the entity has had no business transactions or activities to date.

Subsequent Events

Subsequent events have been evaluated through May 11, 2012, the date these financial statements were available to be issued.

3. Commitments and Contingencies

As of the date of these financial statements, Summit Midstream Partners, LP had no outstanding commitments and contingencies.

F-50

APPENDIX A
FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF
SUMMIT MIDSTREAM PARTNERS, LP

To be filed by amendment.

A-1

APPENDIX B
GLOSSARY OF TERMS

condensate: A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.

dry gas: A gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removed through processing.

end users: The ultimate users and consumers of transported energy products.

Mcf: One thousand cubic feet.

MMBtu: One million British Thermal Units.

MMBtu/d: One million British Thermal Units per day.

MMcf: One million cubic feet.

MMcf/d: One million cubic feet per day.

NGLs: Natural gas liquids. The combination of ethane, propane, normal butane, iso-butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX: New York Mercantile Exchange.

play: A proven geological formation that contains commercial amounts of hydrocarbons.

receipt point: The point where production is received by or into a gathering system or transportation pipeline.

residue gas: The natural gas remaining after being processed or treated.

tailgate: Refers to the point at which processed natural gas and natural gas liquids leave a processing facility for end-use markets.

Tcf: One trillion cubic feet.

throughput volume: The volume of natural gas transported or passing through a pipeline, plant, terminal or other facility during a particular period.

wellhead: The equipment at the surface of a well used to control the well's pressure; also, the point at which the hydrocarbons and water exit the ground.

B-1

Summit Midstream Partners, LP

Common Units
Representing Limited Partner Interests

Prospectus

, 2012

Barclays

BofA Merrill Lynch

Goldman, Sachs & Co.

Morgan Stanley

Until , 2012 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution.

Set forth below are the expenses (other than underwriting discounts, commissions and structuring fees) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the NYSE listing fee, the amounts set forth below are estimates.


SEC registration fee	$	*
FINRA filing fee		23,500
NYSE listing fee		*
Fees and expenses of legal counsel		*
Accounting fees and expenses		*
Transfer agent and registrar fees		*
Printing expenses		*
Miscellaneous		*

Total		*

*: To be filed by amendment.

Item 14. Indemnification of Directors and Officers.

Summit Midstream Partners, LP

Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against any and all claims and demands whatsoever. The section of the prospectus entitled "The Partnership Agreement—Indemnification" discloses that we will generally indemnify officers, directors and affiliates of our general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by reference.

The underwriting agreement to be entered into in connection with the sale of the securities offered pursuant to this registration statement, the form of which will be filed as an exhibit to this registration statement, provides for indemnification of Summit Midstream Partners, LP and our general partner, their officers and directors, and any person who controls our general partner, including indemnification for liabilities under the Securities Act.

Summit Midstream GP, LLC

Subject to any terms, conditions or restrictions set forth in the limited liability company agreement, Section 18-108 of the Delaware Limited Liability Company Act empowers a Delaware limited liability company to indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever.

Under the limited liability agreement of our general partner, in most circumstances, our general partner will indemnify the following persons, to the fullest extent permitted by law, from and against any and all losses, claims, damages, liabilities (joint or several), expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings (whether civil, criminal, administrative or investigative):

•: any person who is or was an affiliate of our general partner (other than us and our subsidiaries);

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•: any person who is or was a member, partner, officer, director, employee, agent or trustee of our general partner or any affiliate of our general partner;
•: any person who is or was serving at the request of our general partner or any affiliate of our general partner as an officer, director, employee, member, partner, agent, fiduciary or trustee of another person; and
•: any person designated by our general partner.

Our general partner will purchase insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of our general partner or any of its direct or indirect subsidiaries.

Item 15. Recent Sales of Unregistered Securities.

On May 10, 2012, in connection with the formation of Summit Midstream Partners LP, we issued (i) the 2.0% general partner interest in us to Summit Midstream GP, LLC for $20, and (ii) a 98% limited partner interest in us to Summit Midstream Partners, LLC for $980, in each case in an offering exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.

Item 16. Exhibits and Financial Schedules.

The following documents are filed as exhibits to this registration statement:

		Description

1.1	**	Form of Underwriting Agreement
3.1	*	Certificate of Limited Partnership of Summit Midstream Partners, LP
3.2	*	Agreement of Limited Partnership of Summit Midstream Partners, LP
3.3	**	Form of Amended and Restated Agreement of Limited Partnership of Summit Midstream Partners, LP
5.1	**	Form of opinion of Latham & Watkins LLP as to the legality of the securities being registered
8.1	**	Form of opinion of Latham & Watkins LLP relating to tax matters
10.1	*	Amendment and Restatement Agreement giving effect to the form of Amended and Restated Revolving Credit Agreement
10.2	*	Form of Amended and Restated Revolving Credit Agreement (included in Exhibit 10.1)
10.3	**	Form of Contribution, Conveyance and Assumption Agreement
10.4		Form of Summit Midstream Partners, LP 2012 Long-Term Incentive Plan
10.5		Form of Phantom Unit Award Agreement
10.6	**†	Amended and Restated Natural Gas Gathering Agreement, dated August 1, 2010, by and between DFW Midstream Services LLC, Chesapeake Energy Marketing, Inc., and Chesapeake Exploration, LLC.
10.7	**†	Second Amended and Restated Individual Transaction Sheet No. 1, dated April 1, 2011, by and between DFW Midstream Services LLC, Chesapeake Energy Marketing, Inc., and Chesapeake Exploration, LLC.
10.8	**†	Amended and Restated Natural Gas Gathering Agreement, dated December 1, 2011, by and between DFW Midstream Services LLC and Carrizo Oil & Gas, Inc.
10.9	**†	Second Amended and Restated Gas Gathering Agreement, dated November 1, 2010, by and between Willams Production RMT Company LLC and Encana Oil & Gas (USA) Inc.
10.10	**†	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.

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		Description

10.11	**†	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.
10.12	**	Employment Agreement, dated September 3, 2009, by and between Summit Midstream Partners, LLC and Steven J. Newby.
10.13	**	Employment Agreement, dated September 15, 2011, by and between Summit Midstream Partners, LLC and Matthew S. Harrison.
21.1	*	List of Subsidiaries of Summit Midstream Partners, LP
23.1		Consent of Deloitte & Touche LLP.
23.2	**	Form of consent of Latham & Watkins LLP (contained in Exhibit 5.1).
23.3	**	Form of consent of Latham & Watkins LLP (contained in Exhibit 8.1).
24.1		Powers of Attorney (contained on the signature page to this Registration Statement).

*: Previously submitted.
**: To be filed by amendment.
†: Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been filed separately with the Securities and Exchange Commission.

Item 17. Undertakings

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1): For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.
(2): For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
(3): That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than

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prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

(4): That, for the purpose of determining liability of the registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities, the undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(i) Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

(ii) If the registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use;

(iii) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

(iv) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

(v) Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with Summit Midstream GP, LLC our general partner, or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to Summit Midstream GP, LLC or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The undersigned registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the company.

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SIGNATURES

Pursuant to the to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Dallas, State of Texas, on[ • ], 2012.

Each person whose signature appears below appoints Steven J. Newby and Brock M. Degeyter, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

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Pursuant to the requirements of the Securities Act of 1933, as amended this Registration Statement has been signed by the following persons in the capacities and the dates indicated.

Signature	Title	Date

/s/	Chief Executive Officer and President (Principal Executive Officer) and Director	[•], 2012
/s/	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	[•], 2012
/s/	Vice President of Finance and Chief Accounting Officer (Principal Accounting Officer)	[•], 2012
/s/	Director	[•], 2012
/s/	Director	[•], 2012
/s/	Director	[•], 2012
/s/	Director	[•], 2012

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EXHIBIT INDEX

The following documents are filed as exhibits to this registration statement:

		Description

1.1	**	Form of Underwriting Agreement
3.1	*	Certificate of Limited Partnership of Summit Midstream Partners, LP
3.2	*	Agreement of Limited Partnership of Summit Midstream Partners, LP
3.3	**	Form of Amended and Restated Agreement of Limited Partnership of Summit Midstream Partners, LP
5.1	**	Form of opinion of Latham & Watkins LLP as to the legality of the securities being registered
8.1	**	Form of opinion of Latham & Watkins LLP relating to tax matters
10.1	*	Amendment and Restatement Agreement giving effect to the form of Amended and Restated Revolving Credit Agreement
10.2	*	Amended and Restated Revolving Credit Agreement (included in Exhibit 10.1)
10.3	**	Form of Contribution, Conveyance and Assumption Agreement
10.4		Form of Summit Midstream Partners, LP 2012 Long-Term Incentive Plan
10.5		Form of Phantom Unit Award Agreement
10.6	**†	Amended and Restated Natural Gas Gathering Agreement, dated August 1, 2010, by and between DFW Midstream Services LLC, Chesapeake Energy Marketing, Inc., and Chesapeake Exploration, LLC.
10.7	**†	Second Amended and Restated Individual Transaction Sheet No. 1, dated April 1, 2011, by and between DFW Midstream Services LLC, Chesapeake Energy Marketing, Inc., and Chesapeake Exploration, LLC.
10.8	**†	Amended and Restated Natural Gas Gathering Agreement, dated December 1, 2011, by and between DFW Midstream Services LLC and Carrizo Oil & Gas, Inc.
10.9	**†	Second Amended and Restated Gas Gathering Agreement, dated November 1, 2010, by and between Willams Production RMT Company LLC and Encana Oil & Gas (USA) Inc.
10.10	**†	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.
10.11	**†	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.
10.12	**	Employment Agreement, dated September 3, 2009, by and between Summit Midstream Partners, LLC and Steven J. Newby.
10.13	**	Employment Agreement, dated September 15, 2011, by and between Summit Midstream Partners, LLC and Matthew S. Harrison.
21.1	*	List of Subsidiaries of Summit Midstream Partners, LP
23.1		Consent of Deloitte & Touche LLP.
23.2	**	Form of consent of Latham & Watkins LLP (contained in Exhibit 5.1).
23.3	**	Form of consent of Latham & Watkins LLP (contained in Exhibit 8.1).
24.1		Powers of Attorney (contained on the signature page to this Registration Statement).

*: Previously submitted.
**: To be filed by amendment.
†: Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been filed separately with the Securities and Exchange Commission.

Exhibit 10.4

SUMMIT MIDSTREAM PARTNERS, LP
2012 LONG-TERM INCENTIVE PLAN

SECTION 1. Purpose of the Plan.

This Summit Midstream Partners, LP 2012 Long-Term Incentive Plan (the “Plan”) has been adopted by Summit Midstream GP, LLC, a Delaware limited liability company (the “Company”), the general partner of Summit Midstream Partners, LP, a Delaware limited partnership (the “Partnership”). The Plan is intended to promote the interests of the Partnership and the Company by providing incentive compensation awards denominated in or based on Units to Employees, Consultants and Directors to encourage superior performance. The Plan is also intended to enhance the ability of the Partnership, the Company and their Affiliates to attract and retain the services of individuals who are essential for the growth and profitability of the Partnership, the Company and their Affiliates and to encourage them to devote their best efforts to advancing the business of the Partnership, the Company and their Affiliates.

SECTION 2. Definitions.

As used in the Plan, the following terms shall have the meanings set forth below:

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

“ASC Topic 718” means Accounting Standards Codification Topic 718, Compensation — Stock Compensation, or any successor accounting standard.

“Award” means an Option, Restricted Unit, Phantom Unit, DER, Substitute Award, Unit Appreciation Right, Unit Award or Profits Interest Unit granted under the Plan.

“Award Agreement” means the written or electronic agreement by which an Award shall be evidenced.

“Board” means the board of directors or board of managers, as the case may be, of the Company.

“Cause” means, unless otherwise set forth in an Award Agreement or other written agreement between the Company and the applicable Participant, a finding by the Committee, before or after the Participant’s termination of Service, of: (i) any material failure by the Participant to perform the Participant’s duties and responsibilities under any written agreement between the Participant and the Company or its Affiliate(s); (ii) any act of fraud, embezzlement, theft or misappropriation by the Participant relating to the Company, the Partnership or any of their Affiliates; (iii) the Participant’s commission of a felony or a crime involving moral turpitude; (iv) any gross negligence or intentional misconduct on the part of the Participant in the conduct of the Participant’s duties and responsibilities with the Company or any Affiliate(s) of the Company or which adversely affects the image, reputation or business of the Company, the

Partnership or their Affiliates; or (v) any material breach by the Participant of any agreement between the Company or any of its Affiliates, on the one hand, and the Participant on the other. The findings and decision of the Committee with respect to such matter, including those regarding the acts of the Participant and the impact thereof, will be final for all purposes.

“Change in Control” means, and shall be deemed to have occurred upon one or more of the following events:

(i) any “person” or “group” within the meaning of Sections 13(d) and 14(d)(2) of the Exchange Act, other than the Company or an Affiliate of the Company (as determined immediately prior to such event), shall become the beneficial owner, by way of merger, acquisition, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the combined voting power of the equity interests in the Company or the Partnership;

(ii) the limited partners of the Partnership approve, in one or a series of transactions, a plan of complete liquidation of the Partnership;

(iii) the sale or other disposition by either the Company or the Partnership of all or substantially all of its assets in one or more transactions to any Person other than the Company, the Partnership or an Affiliate of the Company or the Partnership; or

(iv) a transaction resulting in a Person other than the Company or an Affiliate of the Company (as determined immediately prior to such event) being the sole general partner of the Partnership.

Notwithstanding the foregoing, if a Change in Control constitutes a payment event with respect to any Award which provides for the deferral of compensation and is subject to Section 409A, the transaction or event described in subsection (i), (ii), (iii) or (iv) above with respect to such Award must also constitute a “change in control event,” as defined in Treasury Regulation §1.409A-3(i)(5), and as relates to the holder of such Award, to the extent required to comply with Section 409A.

“Code” means the Internal Revenue Code of 1986, as amended.

“Committee” means the Board, except that it shall mean such committee of the Board as is appointed by the Board to administer the Plan.

“Consultant” means an individual who renders consulting services to the Company, the Partnership or any of their Affiliates.

“DER” means a distribution equivalent right, representing a contingent right to receive an amount in cash, Units, Restricted Units and/or Phantom Units equal in value to the distributions made by the Partnership with respect to a Unit during the period such Award is outstanding.

“Director” means a member of the board of directors or board of managers, as the case may be, of the Company, the Partnership or any of their Affiliates who is not an Employee or a Consultant (other than in that individual’s capacity as a Director).

“Disability” means, unless otherwise set forth in an Award Agreement or other written agreement between the Company and the applicable Participant, as determined by the Committee in its discretion exercised in good faith, a physical or mental condition of a Participant that would entitle him or her to payment of disability income payments under the Company’s, the Partnership’s or one of their Affiliates’ long-term disability insurance policy or plan for employees as then in effect; or in the event that a Participant is not covered, for whatever reason, under any such long-term disability insurance policy or plan for employees or the Company, the Partnership or one of their Affiliates does not maintain such a long-term disability insurance policy, “Disability” means a total and permanent disability within the meaning of Section 22(e)(3) of the Code; provided, however, that if a Disability constitutes a payment event with respect to any Award which provides for the deferral of compensation and is subject to Section 409A, then, to the extent required to comply with Section 409A, the Participant must also be considered “disabled” within the meaning of Section 409A(a)(2)(C) of the Code. A determination of Disability may be made by a physician selected or approved by the Committee and, in this respect, Participants shall submit to an examination by such physician upon request by the Committee.

“Employee” means an employee of the Company, the Partnership or any of their Affiliates.

“Exchange Act” means the Securities Exchange Act of 1934, as amended.

“Fair Market Value” means, as of any given date, the closing sales price on such date during normal trading hours (or, if there are no reported sales on such date, on the last date prior to such date on which there were sales) of the Units on the New York Stock Exchange or, if not listed on such exchange, on any other national securities exchange on which the Units are listed or on an inter-dealer quotation system, in any case, as reported in such source as the Committee shall select. If there is no regular public trading market for the Units, the Fair Market Value of the Units shall be determined by the Committee in good faith and, to the extent applicable, in compliance with the requirements of Section 409A.

“Option” means an option to purchase Units granted pursuant to Section 6(a) of the Plan.

“Other Unit-Based Award” means an award granted pursuant to Section 6(f) of the Plan.

“Participant” means an Employee, Consultant or Director granted an Award under the Plan and any authorized transferee of such individual.

“Partnership Agreement” means the Agreement of Limited Partnership of the Partnership, as it may be amended or amended and restated from time to time.

“Person” shall have the meaning ascribed to such term in Section 3(a)(9) of the Exchange Act and used in Sections 13(d) and 14(d) thereof, including a “group” as defined in Section 13(d) thereof.

“Phantom Unit” means a notional interest granted under the Plan that, to the extent vested, entitles the Participant to receive a Unit or an amount of cash equal to the Fair Market Value of a Unit, as determined by the Committee in its discretion.

“Profits Interest Unit” means to the extent authorized by the Partnership Agreement, an interest in the Partnership that is intended to constitute a “profits interest” within the meaning of the Code, Treasury Regulations promulgated thereunder, and any published guidance by the Internal Revenue Service with respect thereto.

“Restricted Period” means the period established by the Committee with respect to an Award during which the Award remains subject to forfeiture and is either not exercisable by or payable to the Participant, as the case may be.

“Restricted Unit” means a Unit granted pursuant to Section 6(b) of the Plan that is subject to a Restricted Period.

“Securities Act” means the Securities Act of 1933, as amended.

“SEC” means the Securities and Exchange Commission, or any successor thereto.

“Section 409A” means Section 409A of the Code and the Department of Treasury Regulations and other interpretive guidance issued thereunder, including without limitation any such regulations or other guidance that may be issued after the Effective Date (as defined in Section 9 below).

“Service” means service as an Employee, Consultant or Director. The Committee, in its sole discretion, shall determine the effect of all matters and questions relating to terminations of Service, including, without limitation, the questions of whether and when a termination of Service occurred and/or resulted from a discharge for Cause, and all questions of whether particular changes in status or leaves of absence constitute a termination of Service. The Committee, in its sole discretion, subject to the terms of any applicable Award Agreement, may determine that a termination of Service has not occurred in the event of (a) a termination where there is simultaneous commencement by the Participant of a relationship with the Partnership, the Company or any of their Affiliates as an Employee, Director or Consultant or (b) a termination which results in a temporary severance of the service relationship.

“Substitute Award” means an award granted pursuant to Section 6(g) of the Plan.

“Unit” means a Common Unit of the Partnership.

“Unit Appreciation Right” or “UAR” means a contingent right that entitles the holder to receive the excess of the Fair Market Value of a Unit on the exercise date of the UAR over the exercise price of the UAR.

“Unit Award” means an award granted pursuant to Section 6(d) of the Plan.

SECTION 3. Administration.

(a) The Plan shall be administered by the Committee, subject to subsection (b) below; provided, however, that in the event that the Board is not also serving as the Committee, the Board, in its sole discretion, may at any time and from time to time exercise any and all rights and duties of the Committee under the Plan. The governance of the Committee shall be subject to the charter, if any, of the Committee as approved by the Board. Subject to the terms of the Plan and applicable law, and in addition to other express powers and authorizations conferred on the Committee by the Plan, the Committee shall have full power and authority to: (i) designate Participants; (ii) determine the type or types of Awards to be granted to a Participant; (iii) determine the number of Units to be covered by Awards; (iv) determine the terms and conditions of any Award; (v) determine whether, to what extent, and under what circumstances Awards may be settled, exercised, canceled, or forfeited; (vi) interpret and administer the Plan and any instrument or agreement relating to an Award made under the Plan; (vii) establish, amend, suspend, or waive such rules and regulations and appoint such agents as it shall deem appropriate for the proper administration of the Plan; and (viii) make any other determination and take any other action that the Committee deems necessary or desirable for the administration of the Plan. The Committee may correct any defect or supply any omission or reconcile any inconsistency in the Plan or an Award Agreement in such manner and to such extent as the Committee deems necessary or appropriate. Unless otherwise expressly provided in the Plan, all designations, determinations, interpretations, and other decisions under or with respect to the Plan or any Award shall be within the sole discretion of the Committee, may be made at any time and shall be final, conclusive, and binding upon all Persons, including the Company, the Partnership, any of their Affiliates, any Participant and any beneficiary of any Participant.

(b) To the extent permitted by applicable law and the rules of any securities exchange on which the Units are listed, quoted or traded, the Board or Committee may from time to time delegate to a committee of one or more members of the Board or one or more officers of the Company the authority to grant or amend Awards or to take other administrative actions pursuant to Section 3(a); provided, however, that in no event shall an officer of the Company be delegated the authority to grant awards to, or amend awards held by, the following individuals: (i) individuals who are subject to Section 16 of the Exchange Act, or (ii) officers of the Company (or Directors) to whom authority to grant or amend Awards has been delegated hereunder; provided, further, that any delegation of administrative authority shall only be permitted to the extent that it is permissible under applicable provisions of the Code and applicable securities laws and the rules of any securities exchange on which the Units are listed, quoted or traded. Any delegation hereunder shall be subject to such restrictions and limitations as the Board or Committee, as applicable, specifies at the time of such delegation, and the Board or Committee, as applicable, may at any time rescind the authority so delegated or appoint a new delegatee. At all times, the delegatee appointed under this Section 3(b) shall serve in such capacity at the pleasure of the Board and the Committee.

SECTION 4. Units.

(a) Limits on Units Deliverable. Subject to adjustment as provided in Section 4(c), the number of Units that may be delivered with respect to Awards under the Plan is [ ( )]. If any Award is forfeited, cancelled, exercised, paid, or otherwise terminates or expires without the actual delivery of Units pursuant to such Award (for the avoidance of doubt, the grant of Restricted Units is not a delivery of Units for this purpose unless and until such Restricted Units vest and any restrictions placed upon them under the Plan lapse), the Units subject to such Award shall again be available for Awards under the Plan. To the extent permitted by applicable law and securities exchange rules, Substitute Awards and Units issued in assumption of, or in substitution for, any outstanding awards of any entity acquired in any form of combination by the Partnership or any Affiliate thereof shall not be counted against the Units available for issuance pursuant to the Plan. There shall not be any limitation on the number of Awards that may be paid in cash.

(b) Sources of Units Deliverable Under Awards. Any Units delivered pursuant to an Award shall consist, in whole or in part, of Units acquired in the open market, from the Partnership, any Affiliate thereof or any other Person, or Units otherwise issuable by the Partnership, or any combination of the foregoing, as determined by the Committee in its discretion.

(i) Equity Restructuring. With respect to any “equity restructuring” event that could result in an additional compensation expense to the Company or the Partnership pursuant to the provisions of ASC Topic 718 if adjustments to Awards with respect to such event were discretionary, the Committee shall equitably adjust the number and type of Units covered by each outstanding Award and the terms and conditions, including the exercise price and performance criteria (if any), of such Award to equitably reflect such event and shall adjust the number and type of Units (or other securities or property) with respect to which Awards may be granted under the Plan after such event. With respect to any other similar event that would not result in an ASC Topic 718 accounting charge if the adjustment to Awards with respect to such event were subject to discretionary action, the Committee shall have complete discretion to adjust Awards and the number and type of Units (or other securities or property) with respect to which Awards may be granted under the Plan in such manner as it deems appropriate with respect to such other event.

(ii) Other Changes in Capitalization. In the event of any non-cash distribution, Unit split, combination or exchange of Units, merger, consolidation or distribution (other than normal cash distributions) of Partnership assets to unitholders, or any other change affecting the Units of the Partnership, other than an “equity restructuring,” the Committee may make equitable adjustments, if any, to reflect such change with respect to (A) the aggregate number and kind of Units that may be issued under the Plan; (B) the number and kind of Units (or other securities or property) subject to outstanding Awards; (C) the terms and conditions of any outstanding Awards (including, without limitation, any applicable performance targets or

criteria with respect thereto); and (D) the grant or exercise price per Unit for any outstanding Awards under the Plan.

SECTION 5. Eligibility.

Any Employee, Consultant or Director shall be eligible to be designated a Participant and receive an Award under the Plan.

SECTION 6. Awards.

(a) Options and UARs. The Committee shall have the authority to determine the Employees, Consultants and Directors to whom Options and/or UARs shall be granted, the number of Units to be covered by each Option or UAR, the exercise price therefor, the Restricted Period and other conditions and limitations applicable to the exercise of the Option or UAR, including the following terms and conditions and such additional terms and conditions, as the Committee shall determine, that are not inconsistent with the provisions of the Plan. Options which are intended to comply with Treasury Regulation Section 1.409A-1(b)(5)(i)(A) and UARs which are intended to comply with Treasury Regulation Section 1.409A-1(b)(5)(i)(B) or, in each case, any successor regulation, may be granted only if the requirements of Treasury Regulation Section 1.409A-1(b)(5)(iii), or any successor regulation, are satisfied. Options and UARs that are otherwise exempt from or compliant with Section 409A may be granted to any eligible Employee, Consultant or Director.

(i) Exercise Price. The exercise price per Unit purchasable under an Option or subject to a UAR shall be determined by the Committee at the time the Option or UAR is granted but, except with respect to a Substitute Award, may not be less than the Fair Market Value of a Unit as of the date of grant of the Option or UAR.

(ii) Time and Method of Exercise. The Committee shall determine the exercise terms and any applicable Restricted Period with respect to an Option or UAR, which may include, without limitation, provisions for accelerated vesting upon the achievement of specified performance goals and/or other events, and the method or methods by which payment of the exercise price with respect to an Option or UAR may be made or deemed to have been made, which may include, without limitation, cash, check acceptable to the Company, withholding Units having a Fair Market Value on the exercise date equal to the relevant exercise price from the Award, a “cashless” exercise through procedures approved by the Company, or any combination of the foregoing methods.

(iii) Exercise of Options and UARs on Termination of Service. Each Option and UAR Award Agreement shall set forth the extent to which the Participant shall have the right to exercise the Option or UAR following a termination of the Participant’s Service. Unless otherwise determined by the Committee, if the Participant’s Service is terminated for Cause, the Participant’s right to exercise the Option or UAR shall terminate as of the start of business on the effective date of the Participant’s termination. Unless otherwise determined by the Committee, to the extent the Option or UAR is not

vested and exercisable as of the termination of Service, the Option or UAR shall terminate when the Participant’s Service terminates.

(iv) Term of Options and UARs. The term of each Option and UAR shall be stated in the Award Agreement, provided, that the term shall be no more than ten (10) years from the date of grant thereof.

(b) Restricted Units and Phantom Units. The Committee shall have the authority to determine the Employees, Consultants and Directors to whom Restricted Units and/or Phantom Units shall be granted, the number of Restricted Units or Phantom Units to be granted to each such Participant, the applicable Restricted Period, the conditions under which the Restricted Units or Phantom Units may become vested or forfeited and such other terms and conditions, including, without limitation, restrictions on transferability, as the Committee may establish with respect to such Awards.

(i) Payment of Phantom Units. The Committee shall specify, or permit the Participant to elect in accordance with the requirements of Section 409A, the conditions and dates or events upon which the cash or Units underlying an award of Phantom Units shall be issued, which dates or events shall not be earlier than the date on which the Phantom Units vest and become nonforfeitable and which conditions and dates or events shall be subject to compliance with Section 409A (unless the Phantom Units are exempt therefrom).

(ii) Vesting of Restricted Units. Upon or as soon as reasonably practicable following the vesting of each Restricted Unit, subject to satisfying the tax withholding obligations of Section 8(b), the Participant shall be entitled to have the restrictions removed from his or her Unit certificate (or book-entry account, as applicable) so that the Participant then holds an unrestricted Unit.

(c) DERs. The Committee shall have the authority to determine the Employees, Consultants and/or Directors to whom DERs are granted, whether such DERs are tandem or separate Awards, whether the DERs shall be paid directly to the Participant, be credited to a bookkeeping account (with or without interest in the discretion of the Committee), any vesting restrictions and payment provisions applicable to the DERs, and such other provisions or restrictions as determined by the Committee in its discretion, all of which shall be specified in the applicable Award Agreements. Distributions in respect of DERs shall be credited as of the distribution dates during the period between the date an Award is granted to a Participant and the date such Award vests, is exercised, is distributed or expires, as determined by the Committee. Such DERs shall be converted to cash, Units, Restricted Units and/or Phantom Units by such formula and at such time and subject to such limitations as may be determined by the Committee. Tandem DERs may be subject to the same or different vesting restrictions as the tandem Award, or be subject to such other provisions or restrictions as determined by the Committee in its discretion. Notwithstanding the foregoing, DERs shall only be paid in a manner that is either exempt from or in compliance with Section 409A.

(d) Unit Awards. Awards of Units may be granted under the Plan (i) to such Employees, Consultants and/or Directors and in such amounts as the Committee, in its discretion, may select, and (ii) subject to such other terms and conditions, including, without limitation, restrictions on transferability, as the Committee may establish with respect to such Awards.

(e) Profits Interest Units. Any Award consisting of Profits Interest Units may be granted to an Employee, Consultant or Director for the performance of services to or for the benefit of the Partnership (i) in the Participant’s capacity as a partner of the Partnership, (ii) in anticipation of the Participant becoming a partner of the Partnership, or (iii) as otherwise determined by the Committee. At the time of grant, the Committee shall specify the date or dates on which the Profits Interest Units shall vest and become nonforfeitable, and may specify such conditions to vesting as it deems appropriate. Profits Interest Units shall be subject to such restrictions on transferability and other restrictions as the Committee may impose.

(f) Other Unit-Based Awards. Other Unit-Based Awards may be granted under the Plan to such Employees, Consultants and/or Directors as the Committee, in its discretion, may select. An Other Unit-Based Award shall be an award denominated or payable in, valued in or otherwise based on or related to Units, in whole or in part. The Committee shall determine the terms and conditions of any Other Unit-Based Award. Upon vesting, an Other Unit-Based Award may be paid in cash, Units (including Restricted Units) or any combination thereof as provided in the Award Agreement.

(g) Substitute Awards. Awards may be granted under the Plan in substitution of similar awards held by individuals who become Employees, Consultants or Directors as a result of a merger, consolidation or acquisition by the Partnership or an Affiliate of another entity or the assets of another entity. Such Substitute Awards that are Options or UARs may have exercise prices less than the Fair Market Value of a Unit on the date of the substitution if such substitution complies with Section 409A and other applicable laws and securities exchange rules.

(h) General.

(i) Forfeitures. Except as otherwise provided in the terms of an Award Agreement, upon termination of a Participant’s Service for any reason during an applicable Restricted Period, all outstanding, unvested Awards held by such Participant shall be automatically forfeited by the Participant. The Committee may, in its discretion, waive in whole or in part such forfeiture with respect to any such Award; provided, that any such waiver shall be effective only to the extent that such waiver will not cause any Award intended to satisfy the requirements of Section 409A to fail to satisfy such requirements.

(ii) Awards May Be Granted Separately or Together. Awards may, in the discretion of the Committee, be granted either alone or in addition to, in tandem with, or in substitution for any other Award granted under the Plan or any award granted under any other plan of the Company or any Affiliate. Awards granted in addition to or in tandem with other Awards or awards granted under any other plan of the Company or any Affiliate may be granted either at the same time as or at a different time from the grant of such other Awards or awards.

(iii) Limits on Transfer of Awards.

(A) Except as provided in paragraph (C) below, each Option and UAR shall be exercisable only by the Participant during the Participant’s lifetime, or by the person to whom the Participant’s rights shall pass by will or the laws of descent and distribution.

(B) Except as provided in paragraph (C) below, no Award and no right under any such Award may be assigned, alienated, pledged, attached, sold or otherwise transferred or encumbered by a Participant other than by will or the laws of descent and distribution and any such purported assignment, alienation, pledge, attachment, sale, transfer or encumbrance shall be void and unenforceable against the Company, the Partnership or any Affiliate.

(C) The Committee may provide in an Award Agreement that an Award may, on such terms and conditions as the Committee may from time to time establish, be transferred by a Participant without consideration to any “family member” of the Participant, as defined in the instructions to use of the Form S-8 Registration Statement under the Securities Act, as applicable, or any other transferee specifically approved by the Committee after taking into account any state, federal, local or foreign tax and securities laws applicable to transferable Awards. In addition, vested Units may be transferred to the extent permitted by the Partnership Agreement and not otherwise prohibited by the Award Agreement or any other agreement restricting the transfer of such Units.

(iv) Term of Awards. Subject to Section 6(a)(iv) above, the term of each Award, if any, shall be for such period as may be determined by the Committee.

(v) Unit Certificates. Unless otherwise determined by the Committee or required by any applicable law, rule or regulation, neither the Company nor the Partnership shall deliver to any Participant certificates evidencing Units issued in connection with any Award and instead such Units shall be recorded in the books of the Partnership (or, as applicable, its transfer agent or equity plan administrator). All certificates for Units or other securities of the Partnership delivered under the Plan and all Units issued pursuant to book entry procedures pursuant to any Award or the exercise thereof shall be subject to such stop-transfer orders and other restrictions as the Committee may deem advisable under the Plan or the rules, regulations, and/or other requirements of the SEC, any securities exchange upon which such Units or other securities are then listed, and any applicable federal or state laws, and the Committee may cause a legend or legends to be inscribed on any such certificates or book entry to make appropriate reference to such restrictions.

(vi) Consideration for Grants. To the extent permitted by applicable law, Awards may be granted for such consideration, including services, as the Committee shall determine.

(vii) Delivery of Units or other Securities and Payment by Participant of Consideration. Notwithstanding anything in the Plan or any Award Agreement to the contrary, subject to compliance with Section 409A, the Company shall not be required to issue or deliver any certificates or make any book entries evidencing Units pursuant to the exercise or vesting of any Award, unless and until the Board or the Committee has determined, with advice of counsel, that the issuance of such Units is in compliance with all applicable laws, regulations of governmental authorities and, if applicable, the requirements of any securities exchange on which the Units are listed or traded, and the Units are covered by an effective registration statement or applicable exemption from registration. In addition to the terms and conditions provided herein, the Board or the Committee may require that a Participant make such reasonable covenants, agreements, and representations as the Board or the Committee, in its discretion, deems advisable in order to comply with any such laws, regulations, or requirements. Without limiting the generality of the foregoing, the delivery of Units pursuant to the exercise or vesting of an Award may be deferred for any period during which, in the good faith determination of the Committee, the Company is not reasonably able to obtain or deliver Units pursuant to such Award without violating applicable law or the applicable rules or regulations of any governmental agency or authority or securities exchange. No Units or other securities shall be delivered pursuant to any Award until payment in full of any amount required to be paid pursuant to the Plan or the applicable Award Agreement (including, without limitation, any exercise price or tax withholding) is received by the Company.

SECTION 7. Amendment and Termination; Certain Transactions.

Except to the extent prohibited by applicable law:

(a) Amendments to the Plan. Except as required by applicable law or the rules of the principal securities exchange, if any, on which the Units are traded and subject to Section 7(b)

below, the Board or the Committee may amend, alter, suspend, discontinue, or terminate the Plan in any manner without the consent of any partner, Participant, other holder or beneficiary of an Award, or any other Person. The Board shall obtain securityholder approval of any Plan amendment to the extent necessary to comply with applicable law or securities exchange listing standards or rules.

(b) Amendments to Awards. Subject to Section 7(a) above, the Committee may waive any conditions or rights under, amend any terms of, or alter any Award theretofore granted, provided that no change, other than pursuant to Section 7(c) below, in any Award shall materially reduce the rights or benefits of a Participant with respect to an Award without the consent of such Participant.

(c) Actions Upon the Occurrence of Certain Events. Upon the occurrence of a Change in Control, any transaction or event described in Section 4(c) above, any change in applicable laws or regulations affecting the Plan or Awards hereunder, or any change in accounting principles affecting the financial statements of the Company or the Partnership, the Committee, in its sole discretion, without the consent of any Participant or holder of an Award, and on such terms and conditions as it deems appropriate, may take any one or more of the following actions:

(i) provide for either (A) the termination of any Award in exchange for a payment in an amount, if any, equal to the amount that would have been attained upon the exercise of such Award or realization of the Participant’s rights under such Award (and, for the avoidance of doubt, if as of the date of the occurrence of such transaction or event, the Committee determines in good faith that no amount would have been payable upon the exercise of such Award or realization of the Participant’s rights, then such Award may be terminated by the Company without payment) or (B) the replacement of such Award with other rights or property selected by the Committee in its sole discretion having an aggregate value not exceeding the amount that could have been attained upon the exercise of such Award or realization of the Participant’s rights had such Award been currently exercisable or payable or fully vested;

(ii) provide that such Award be assumed by the successor or survivor entity, or a parent or subsidiary thereof, or be exchanged for similar options, rights or awards covering the equity of the successor or survivor, or a parent or subsidiary thereof, with appropriate adjustments as to the number and kind of equity interests and prices;

(iii) make adjustments in the number and type of Units (or other securities or property) subject to outstanding Awards, the number and kind of outstanding Awards, the terms and conditions of (including the exercise price), and/or the vesting and performance criteria included in, outstanding Awards;

(iv) provide that such Award shall vest or become exercisable or payable, notwithstanding anything to the contrary in the Plan or the applicable Award Agreement; and

(v) provide that the Award cannot be exercised or become payable after such event and shall terminate upon such event.

Notwithstanding the foregoing, (i) with respect to an above event that constitutes an “equity restructuring” that would be subject to a compensation expense pursuant ASC Topic 718, the provisions in Section 4(c) above shall control to the extent they are in conflict with the discretionary provisions of this Section 7, provided, however, that nothing in this Section 7(c) or Section 4(c) above shall be construed as providing any Participant or any beneficiary of an Award any rights with respect to the “time value,” “economic opportunity” or “intrinsic value” of an Award or limiting in any manner the Committee’s actions that may be taken with respect to an Award as set forth in this Section 7 or in Section 4(c) above; and (ii) no action shall be taken under this Section 7 which shall cause an Award to result in taxation under Section 409A, to the extent applicable to such Award.

SECTION 8. General Provisions.

(a) No Rights to Award. No Person shall have any claim to be granted any Award under the Plan, and there is no obligation for uniformity of treatment of Participants, including the treatment upon termination of Service. The terms and conditions of Awards need not be the same with respect to each recipient.

(b) Tax Withholding. Unless other arrangements have been made that are acceptable to the Company, the Company or any Affiliate thereof is authorized to deduct or withhold, or cause to be deducted or withheld, from any Award, from any payment due or transfer made under any Award, or from any compensation or other amount owing to a Participant the amount (in cash or Units, including Units that would otherwise be issued pursuant to such Award or other property) of any applicable taxes payable in respect of an Award, including its grant, its exercise, the lapse of restrictions thereon, or any payment or transfer thereunder or under the Plan, and to take such other action as may be necessary in the opinion of the Company to satisfy its withholding obligations for the payment of such taxes. In the event that Units that would otherwise be issued pursuant to an Award are used to satisfy such withholding obligations, the number of Units which may be so withheld or surrendered shall be limited to the number of Units which have a Fair Market Value on the date of withholding equal to the aggregate amount of such liabilities based on the minimum statutory withholding rates for federal, state, local and foreign income tax and payroll tax purposes that are applicable to such supplemental taxable income.

(c) No Right to Employment or Services. The grant of an Award shall not be construed as giving a Participant the right to be retained in the employ of the Company, the Partnership or any of their Affiliates, continue consulting services or to remain on the Board, as applicable. Furthermore, the Company, the Partnership and/or an Affiliate thereof may at any time dismiss a Participant from employment or consulting free from any liability or any claim under the Plan, unless otherwise expressly provided in the Plan, any Award Agreement or other written agreement between any such entity and the Participant.

(d) No Rights as Unitholder. Except as otherwise provided herein, a Participant shall have none of the rights of a unitholder with respect to Units covered by any Award unless and until the Participant becomes the record owner of such Units.

(e) Section 409A. To the extent that the Committee determines that any Award granted under the Plan is subject to Section 409A, the Award Agreement evidencing such Award shall include the terms and conditions required by Section 409A. To the extent applicable, the Plan and Award Agreements shall be interpreted in accordance with Section 409A. Notwithstanding any provision of the Plan to the contrary, in the event that following the Effective Date (as defined in Section 9 below), the Committee determines that any Award may be subject to Section 409A, the Committee may adopt such amendments to the Plan and the applicable Award Agreement, adopt other policies and procedures (including amendments, policies and procedures with retroactive effect), and/or take any other actions that the Committee determines are necessary or appropriate to preserve the intended tax treatment of the Award, including without limitation, actions intended to (i) exempt the Award from Section 409A, or (ii) comply with the requirements of Section 409A; provided, however, that nothing herein shall create any obligation on the part of the Committee, the Partnership, the Company or any of their Affiliates to adopt any such amendment, policy or procedure or take any such other action, nor shall the Committee, the Partnership, the Company or any of their Affiliates have any liability for failing to do so. Notwithstanding any provision in the Plan to the contrary, the time of payment with respect to any Award that is subject to Section 409A shall not be accelerated, except as permitted under Treasury Regulation Section 1.409A-3(j)(4).

(f) Lock-Up Agreement. Each Participant shall agree, if so requested by the Company or the Partnership and any underwriter in connection with any public offering of securities of the Partnership or any Affiliate, not to directly or indirectly offer, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant for the sale of or otherwise dispose of or transfer any Units held by it for such period, not to exceed one hundred eighty (180) days following the effective date of the relevant registration statement filed under the Securities Act in connection with such public offering, as such underwriter shall specify reasonably and in good faith. The Company or the Partnership may impose stop-transfer instructions with respect to securities subject to the foregoing restrictions until the end of such 180-day period. Notwithstanding the foregoing, the 180-day period may be extended for up to such number of additional days as is deemed necessary by such underwriter or the Company or Partnership to continue coverage by research analysts in accordance with FINRA Rule 2711 or any successor rule.

(g) Compliance with Laws. The Plan, the granting and vesting of Awards under the Plan and the issuance and delivery of Units and the payment of money under the Plan or under Awards granted or awarded hereunder are subject to compliance with all applicable federal, state, local and foreign laws, rules and regulations (including but not limited to state, federal and foreign securities law and margin requirements), the rules of any securities exchange or automated quotation system on which the Units are listed, quoted or traded, and to such approvals by any listing, regulatory or governmental authority as may, in the opinion of counsel for the Company or the Partnership, be necessary or advisable in connection therewith. Any securities delivered under the Plan shall be subject to such restrictions, and the Person acquiring

such securities shall, if requested by the Company or the Partnership, provide such assurances and representations to the Company or the Partnership as the Company or the Partnership may deem necessary or desirable to assure compliance with all applicable legal requirements. To the extent permitted by applicable law, the Plan and Awards granted or awarded hereunder shall be deemed amended to the extent necessary to conform to such laws, rules and regulations. In the event an Award is granted to or held by a Participant who is employed or providing services outside the United States, the Committee may, in its sole discretion, modify the provisions of the Plan or of such Award as they pertain to such Participant to comply with applicable foreign law or to recognize differences in local law, currency or tax policy. The Committee may also impose conditions on the grant, issuance, exercise, vesting, settlement or retention of Awards in order to comply with such foreign law and/or to minimize the Company’s or the Partnership’s obligations with respect to tax equalization for Participants employed outside their home country.

(h) Governing Law. The validity, construction, and effect of the Plan and any rules and regulations relating to the Plan shall be determined in accordance with the laws of the State of Delaware without regard to its conflicts of laws principles.

(i) Severability. If any provision of the Plan or any Award is or becomes, or is deemed to be, invalid, illegal, or unenforceable in any jurisdiction or as to any Person or Award, or would disqualify the Plan or any Award under any law deemed applicable by the Committee, such provision shall be construed or deemed amended to conform to the applicable law or, if it cannot be construed or deemed amended without, in the determination of the Committee, materially altering the intent of the Plan or the Award, such provision shall be stricken as to such jurisdiction, Person or Award and the remainder of the Plan and any such Award shall remain in full force and effect.

(j) Other Laws. The Committee may refuse to issue or transfer any Units or other consideration under an Award if, in its sole discretion, it determines that the issuance or transfer of such Units or such other consideration might violate any applicable law or regulation, the rules of the principal securities exchange on which the Units are then traded, or entitle the Partnership or an Affiliate to recover the same under Section 16(b) of the Exchange Act, and any payment tendered to the Company by a Participant, other holder or beneficiary in connection with the exercise of such Award shall be promptly refunded to the relevant Participant, holder or beneficiary.

(k) No Trust or Fund Created. Neither the Plan nor any Award shall create or be construed to create a trust or separate fund of any kind or a fiduciary relationship between the Company, the Partnership or any of their Affiliates, on the one hand, and a Participant or any other Person, on the other hand. To the extent that any Person acquires a right to receive payments pursuant to an Award, such right shall be no greater than the right of any general unsecured creditor of the Partnership or any participating Affiliate of the Partnership.

(l) No Fractional Units. No fractional Units shall be issued or delivered pursuant to the Plan or any Award, and the Committee shall determine whether cash, other securities, or other property shall be paid or transferred in lieu of any fractional Units or whether such fractional Units or any rights thereto shall be canceled, terminated, or otherwise eliminated.

(m) Headings. Headings are given to the Sections and subsections of the Plan solely as a convenience to facilitate reference. Such headings shall not be deemed in any way material or relevant to the construction or interpretation of the Plan or any provision hereof.

(n) No Guarantee of Tax Consequences. None of the Board, the Committee, the Company or the Partnership provides or has provided any tax advice to any Participant or any other Person or makes or has made any assurance, commitment or guarantee that any federal, state or local tax treatment will (or will not) apply or be available to any Participant or other Person.

(o) Clawback. To the extent required by applicable law or any applicable securities exchange listing standards, or as otherwise determined by the Committee, Awards and amounts paid or payable pursuant to or with respect to Awards shall be subject to the provisions of any clawback policy implemented by the Company, which clawback policy may provide for forfeiture, repurchase and/or recoupment of Awards and amounts paid or payable pursuant to or with respect to Awards. Notwithstanding any provision of this Plan or any Award Agreement to the contrary, the Company reserves the right, without the consent of any Participant, to adopt any such clawback policies and procedures, including such policies and procedures applicable to this Plan or any Award Agreement with retroactive effect.

(p) Facility Payment. Any amounts payable hereunder to any Person under legal disability or who, in the judgment of the Committee, is unable to manage properly his or her financial affairs, may be paid to the legal representative of such Person, or may be applied for the benefit of such Person in any manner that the Committee may select, and the Partnership, the Company and all of their Affiliates shall be relieved of any further liability for payment of such amounts.

SECTION 9. Term of the Plan.

The Plan shall be effective on the date on which the Plan is adopted by the Board (the “Effective Date”) and shall continue until the earliest of (i) the date terminated by the Board, or (ii) the tenth (10th) anniversary of the date on which the Plan is adopted by the Board. However, any Award granted prior to such termination, and the authority of the Board or the Committee to amend, alter, adjust, suspend, discontinue, or terminate any such Award or to waive any conditions or rights under such Award, shall extend beyond such termination date. The Plan shall, within twelve (12) months after the date of the Board’s initial adoption of the Plan, be submitted for approval by a majority of the outstanding Units of the Partnership entitled to vote.

Exhibit 10.5

SUMMIT MIDSTREAM PARTNERS, LP

2012 LONG-TERM INCENTIVE PLAN

PHANTOM UNIT AGREEMENT

Pursuant to this Phantom Unit Agreement, dated as of [ ], 2012 (this “Agreement”), Summit Midstream GP, LLC (the “Company”), as the general partner of Summit Midstream Partners, LP (the “Partnership”), hereby grants to [ ] (the “Participant”) the following award of Phantom Units (“Phantom Units”), pursuant and subject to the terms and conditions of this Agreement and the Summit Midstream Partners, LP 2012 Long-Term Incentive Plan (the “Plan”), the terms and conditions of which are hereby incorporated into this Agreement by reference. In the event of any conflict between the terms of this Agreement and the Plan, the terms of the Plan shall control. Each Phantom Unit shall constitute a Phantom Unit under the terms of the Plan and is hereby granted in tandem with a corresponding DER, as further detailed in Section 3 below. Except as otherwise expressly provided herein, all capitalized terms used in this Agreement, but not defined, shall have the meanings provided in the Plan.

This Award requires your acceptance by executing and returning the signature page hereto within [ ] days of the Grant Date and may be revoked if not so accepted.

GRANT NOTICE

Subject to the terms and conditions of this Agreement, the principal features of this Award are as follows:

Number of Phantom Units: [ ] Phantom Units

Grant Date: [ ], 2012

Vesting of Phantom Units: [ ]

Termination of Phantom Units: In the event of a termination of the Participant’s Service for any reason, all Phantom Units that have not vested prior to or in connection with such termination of Service shall thereupon automatically be forfeited by the Participant without further action and without payment of consideration therefor.

Payment of Phantom Units: Vested Phantom Units shall be paid to the Participant in the form of Units and/or cash as set forth in Section 5 below.

DERs: Each Phantom Unit granted under this Agreement shall be issued in tandem with a corresponding DER, which shall entitle the Participant to receive payments in an amount equal to Partnership distributions in accordance with Section 3 below.

TERMS AND CONDITIONS OF PHANTOM UNITS

1. Grant. The Company hereby grants to the Participant, as of the Grant Date, an award of Phantom Units as set forth in the Grant Notice, subject to all of the terms and conditions contained in this Agreement and the Plan.

2. Phantom Units. Subject to Section 4 below, each Phantom Unit that vests shall represent the right to receive payment, in accordance with Section 5 below, in the form of one (1) Unit. Unless and until a Phantom Unit vests, the Participant will have no right to payment in respect of such Phantom Unit. Prior to actual payment in respect of any vested Phantom Unit, such Phantom Unit will represent an unsecured obligation of the Partnership, payable (if at all) only from the general assets of the Partnership.

3. Grant of Tandem DER. Each Phantom Unit granted hereunder is hereby granted in tandem with a corresponding DER, which DER shall remain outstanding from the Grant Date until the earlier of the payment or forfeiture of the Phantom Unit to which it corresponds. Each vested DER shall entitle the Participant to receive payments, subject to and in accordance with this Agreement, in an amount equal to any distributions made by the Partnership in respect of the Unit underlying the Phantom Unit to which such DER relates. Such payments shall be made in cash to the extent the corresponding distribution was made in cash. The Company shall establish, with respect to each Phantom Unit, a separate DER bookkeeping account for such Phantom Unit (a “DER Account”), which shall be credited (without interest) on the applicable distribution dates with an amount equal to any distributions made by the Partnership during the period that such Phantom Unit remains outstanding with respect to the Unit underlying the Phantom Unit to which such DER relates. Upon the vesting of a Phantom Unit, the DER (and the DER Account) with respect to such vested Phantom Unit shall also become vested. Similarly, upon the forfeiture of a Phantom Unit, the DER (and the DER Account) with respect to such forfeited Phantom Unit shall also be forfeited. DERs shall not entitle the Participant to any payments relating to distributions occurring after the earlier to occur of the applicable Phantom Unit payment date or the forfeiture of the Phantom Unit underlying such DER. The DERs and any amounts that may become distributable in respect thereof shall be treated separately from the Phantom Units and the rights arising in connection therewith for purposes of Section 409A of the Code (including for purposes of the designation of the time and form of payments required by Section 409A of the Code).

4. Vesting and Termination.

(a) Vesting. Subject to Section 4(c) below, the Phantom Units shall vest in such amounts and at such times as are set forth in the Grant Notice above.

(b) Accelerated Vesting. Subject to Section 4(c) below, the Phantom Units shall vest in full upon the occurrence of any of the following events: (i) a termination of the Participant’s Service by the Company or the Partnership during the twelve month period immediately following a Change in Control, other than for Cause, (ii) a termination of the Participant’s Service by reason of the Participant’s death or Disability, or (iii) or otherwise as forth in a written agreement between the Company and the Participant.

(c) Forfeiture. Notwithstanding the foregoing, in the event of a termination of the Participant’s Service for any reason, all Phantom Units that have

not vested prior to or in connection with such termination of Service shall thereupon automatically be forfeited by the Participant without further action and without payment of consideration therefor. No portion of the Phantom Units which has not become vested at the date of the Participant’s termination of Service shall thereafter become vested.

(d) Payment. Except as otherwise provided in a written agreement between the Company and the Participant, vested Phantom Units shall be subject to the payment provisions set forth in Section 5 below.

5. Payment of Phantom Units and DERs.

(a) Phantom Units. Unpaid, vested Phantom Units shall be paid to the Participant in the form of Units or in the Company’s sole discretion cash in an amount equal to the Fair Market Value of a Unit, in a lump-sum as soon as reasonably practical, but not later than forty-five (45) days, following the date on which such Phantom Units vest. Payments of any Phantom Units that vest in accordance herewith shall be made to the Participant (or in the event of the Participant’s death, to the Participant’s estate) in whole Units or cash in accordance with this Section 5.

(b) DERs. Unpaid, vested DERs shall be paid to the Participant as follows: as soon as reasonably practical, but not later than forty-five (45) days, following the date on which a Phantom Unit and related DER vests, the Participant shall be paid an amount in cash equal to the amount then credited to the DER Account maintained with respect to such Phantom Unit.

(c) Potential Six-Month Delay. Notwithstanding anything to the contrary in this Agreement, no amounts payable under this Agreement shall be paid to the Participant prior to the expiration of the six (6)-month period following his “separation from service” (within the meaning of Treasury Regulation Section 1.409A-1(h)) (a “Separation from Service”) to the extent that the Company determines that paying such amounts prior to the expiration of such six (6)-month period would result in a prohibited distribution under Section 409A(a)(2)(B)(i) of the Code. If the payment of any such amounts is delayed as a result of the previous sentence, then on the first business day following the end of the applicable six (6)-month period (or such earlier date upon which such amounts can be paid under Section 409A of the Code without resulting in a prohibited distribution, including as a result of the Participant’s death), such amounts shall be paid to the Participant.

6. Tax Withholding. The Company and/or its Affiliates shall have the authority and the right to deduct or withhold, or to require the Participant to remit to the Company and/or its Affiliates, an amount sufficient to satisfy all applicable federal, state and local taxes (including the Participant’s employment tax obligations) required by law to be withheld with respect to any taxable event arising in connection with the Phantom Units and the DERs. In addition, the Company and/or its Affiliates shall have the authority and right to satisfy such withholding amounts from proceeds of the sale of Units acquired upon vesting of the Phantom Units either through a voluntary sale or through a mandatory sale arranged by the Company (on the Participants’s behalf pursuant to this authorization). In satisfaction of the foregoing requirement, unless otherwise determined by the Committee or the Company, the Company and/or its Affiliates shall withhold Units otherwise issuable in respect of such Phantom Units having a Fair Market Value equal to the sums required to be

withheld. In the event that Units that would otherwise be issued in payment of the Phantom Units are used to satisfy such withholding obligations, the number of Units which shall be so withheld shall be limited to the number of Units which have a Fair Market Value on the date of withholding equal to the aggregate amount of such liabilities based on the minimum statutory withholding rates for federal, state, local and foreign income tax and payroll tax purposes that are applicable to such supplemental taxable income.

7. Rights as Unit Holder. Neither the Participant nor any person claiming under or through the Participant shall have any of the rights or privileges of a holder of Units in respect of any Units that may become deliverable hereunder unless and until certificates representing such Units shall have been issued or recorded in book entry form on the records of the Partnership or its transfer agents or registrars, and delivered in certificate or book entry form to the Participant or any person claiming under or through the Participant.

8. Non-Transferability. Neither the Phantom Units nor any right of the Participant under the Phantom Units may be assigned, alienated, pledged, attached, sold or otherwise transferred or encumbered by the Participant (or any permitted transferee) other than by will or the laws of descent and distribution and any such purported assignment, alienation, pledge, attachment, sale, transfer or encumbrance shall be void and unenforceable against the Company, the Partnership and any of their Affiliates.

9. Distribution of Units. Unless otherwise determined by the Committee or required by any applicable law, rule or regulation, neither the Company nor the Partnership shall deliver to the Participant certificates evidencing Units issued pursuant to this Agreement and instead such Units shall be recorded in the books of the Partnership (or, as applicable, its transfer agent or equity plan administrator). All certificates for Units issued pursuant to this Agreement and all Units issued pursuant to book entry procedures hereunder shall be subject to such stop transfer orders and other restrictions as the Company may deem advisable under the Plan or the rules, regulations, and other requirements of the Securities Exchange Commission, any stock exchange upon which such Units are then listed, and any applicable federal or state laws, and the Company may cause a legend or legends to be inscribed on any such certificates or book entry to make appropriate reference to such restrictions. In addition to the terms and conditions provided herein, the Company may require that the Participant make such covenants, agreements, and representations as the Company, in its sole discretion, deems advisable in order to comply with any such laws, regulations, or requirements. No fractional Units shall be issued or delivered pursuant to the Phantom Units and the Committee shall determine whether cash, other securities, or other property shall be paid or transferred in lieu of fractional Units or whether such fractional Units or any rights thereto shall be canceled, terminated, or otherwise eliminated.

10. Partnership Agreement. Units issued upon payment of the Phantom Units shall be subject to the terms of the Plan and the Partnership Agreement. Upon the issuance of Units to the Participant, the Participant shall, automatically and without further action on his or her part, (i) be admitted to the Partnership as a Limited Partner (as defined in the Partnership Agreement) with respect to the Units, and (ii) become bound, and be deemed to have agreed to be bound, by the terms of the Partnership Agreement.

11. No Effect on Service. Nothing in this Agreement or in the Plan shall be construed as giving the Participant the right to be retained in the employ or service of the Company or any Affiliate thereof. Furthermore, the Company and its Affiliates may at any time dismiss the Participant from employment or consulting free from any liability or any

claim under the Plan or this Agreement, unless otherwise expressly provided in the Plan, this Agreement or any other written agreement between the Participant and the Company or an Affiliate thereof.

12. Severablility. If any provision of this Agreement is or becomes or is deemed to be invalid, illegal, or unenforceable in any jurisdiction, such provision shall be construed or deemed amended to conform to the applicable law or, if it cannot be construed or deemed amended without, in the determination of the Committee, materially altering the intent of this Agreement, such provision shall be stricken as to such jurisdiction, and the remainder of this Agreement shall remain in full force and effect.

13. Tax Consultation. None of the Board, the Committee, the Company nor the Partnership has made any warranty or representation to Participant with respect to the income tax consequences of the issuance of the Phantom Units, the DERs, the Units or the transactions contemplated by this Agreement, and the Participant represents that he or she is in no manner relying on such entities or their representatives for tax advice or an assessment of such tax consequences. The Participant understands that the Participant may suffer adverse tax consequences in connection with the Phantom Units and DERs granted pursuant to this Agreement. The Participant represents that the Participant has consulted with any tax consultants that the Participant deems advisable in connection with the Phantom Units and DERs.

14. Amendments, Suspension and Termination. Subject to Section 7(a) of the Plan, the Committee may waive any conditions or rights under, amend any terms of, or alter this Agreement at any time, provided that no such change, other than pursuant to Section 7(c) of the Plan, shall materially reduce the rights or benefits of the Participant without the Participant’s consent.

15. Lock-Up Agreement. The Participant shall agree, if so requested by the Company or the Partnership and any underwriter in connection with any public offering of securities of the Partnership or any Affiliate thereof, not to directly or indirectly offer, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant for the sale of or otherwise dispose of or transfer any Units held by him or her for such period, not to exceed one hundred eighty (180) days following the effective date of the relevant registration statement filed under the Securities Act in connection with such public offering, as such underwriter shall specify reasonably and in good faith. The Company or the Partnership may impose stop-transfer instructions with respect to securities subject to the foregoing restrictions until the end of such 180-day period. Notwithstanding the foregoing, the 180-day period may be extended for up to such number of additional days as is deemed necessary by such underwriter or the Company or Partnership to continue coverage by research analysts in accordance with FINRA Rule 2711 or any successor rule.

16. Conformity to Securities Laws. The Participant acknowledges that the Plan and this Agreement are intended to conform to the extent necessary with all provisions of the Securities Act and the Exchange Act, any and all regulations and rules promulgated by the Securities and Exchange Commission thereunder, and all applicable state securities laws and regulations. Notwithstanding anything herein to the contrary, the Plan shall be administered, and the Phantom Units and DERs are granted, only in such a manner as to conform to such laws, rules and regulations. To the extent permitted by applicable law, the Plan and this Agreement shall be deemed amended to the extent necessary to conform to

such laws, rules and regulations.

17. Code Section 409A. None of the Phantom Units, the DERs or any amounts paid pursuant to this Agreement are intended to constitute or provide for a deferral of compensation that is subject to Section 409A of the Code. Nevertheless, to the extent that the Committee determines that the Phantom Units or DERs may not be exempt from (or compliant with) Section 409A of the Code, the Committee may (but shall not be required to) amend this Agreement in a manner intended to comply with the requirements of Section 409A of the Code or an exemption therefrom (including amendments with retroactive effect), or take any other actions as it deems necessary or appropriate to (a) exempt the Phantom Units or DERs from Section 409A of the Code and/or preserve the intended tax treatment of the benefits provided with respect to the Phantom Units or DERs, or (b) comply with the requirements of Section 409A of the Code. To the extent applicable, this Agreement shall be interpreted in accordance with the provisions of Section 409A of the Code. Notwithstanding anything in this Agreement to the contrary, to the extent that any payment or benefit hereunder constitutes non-exempt “nonqualified deferred compensation” for purposes of Section 409A of the Code, and such payment or benefit would otherwise be payable or distributable hereunder by reason of the Participant’s termination of Service, all references to the Participant’s termination of Service shall be construed to mean a Separation from Service, and the Participant shall not be considered to have a termination of Service unless such termination constitutes a Separation from Service with respect to the Participant.

18. Adjustments; Clawback. The Participant acknowledges that the Phantom Units are subject to modification and termination in certain events as provided in this Agreement and Section 7 of the Plan. The Participant further acknowledges that the Phantom Units, DERs and Units issuable hereunder shall be subject to the provisions of any clawback policy that may be adopted as provided in Section 8(o) of the Plan.

19. Successors and Assigns. The Company or the Partnership may assign any of its rights under this Agreement to single or multiple assignees, and this Agreement shall inure to the benefit of the successors and assigns of the Company and the Partnership. Subject to the restrictions on transfer contained herein, this Agreement shall be binding upon the Participant and his or her heirs, executors, administrators, successors and assigns.

20. Governing Law. The validity, construction, and effect of this Agreement and any rules and regulations relating to this Agreement shall be determined in accordance with the laws of the State of Delaware without regard to its conflicts of laws principles.

21. Consent to Jurisdiction and Services of Process; Appointment of Agent. NOTWITHSTANDING ANYTHING TO THE CONTRARY IN THE PARTNERSHIP AGREEMENT, EACH PARTY TO THIS AGREEMENT HEREBY CONSENTS TO THE EXCLUSIVE JURISDICTION OF THE UNITED STATES DISTRICT COURT FOR THE SOUTHERN DISTRICT OF NEW YORK AND OF THE STATE COURTS LOCATED IN THE STATE OF NEW YORK IN NEW YORK COUNTY AND IRREVOCABLY AGREES THAT ALL ACTIONS OR PROCEEDINGS ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE PHANTOM UNITS, SHALL BE LITIGATED IN SUCH COURTS. EACH PARTY (a) CONSENTS TO SUBMIT HIMSELF, HERSELF OR ITSELF TO THE PERSONAL JURISDICTION OF SUCH COURTS FOR SUCH ACTIONS OR PROCEEDINGS, (b) AGREES THAT HE, SHE OR IT WILL NOT ATTEMPT TO DENY OR DEFEAT SUCH PERSONAL JURISDICTION BY MOTION OR OTHER REQUEST FOR LEAVE FROM ANY SUCH COURT, AND

(c) AGREES THAT HE, SHE OR IT WILL NOT BRING ANY SUCH ACTION OR PROCEEDING IN ANY COURT OTHER THAN SUCH COURTS. EACH PARTY ACCEPTS FOR HIMSELF, HERSELF OR ITSELF AND IN CONNECTION WITH SUCH PARTY’S PROPERTIES, GENERALLY AND UNCONDITIONALLY, THE EXCLUSIVE AND IRREVOCABLE JURISDICTION AND VENUE OF THE AFORESAID COURTS AND WAIVES ANY DEFENSE OF FORUM NON CONVENIENS, AND IRREVOCABLY AGREES TO BE BOUND BY ANY NON-APPEALABLE JUDGMENT RENDERED THEREBY IN CONNECTION WITH SUCH ACTIONS OR PROCEEDINGS. A COPY OF ANY SERVICE OF PROCESS SERVED UPON THE PARTIES SHALL BE MAILED BY REGISTERED MAIL TO THE RESPECTIVE PARTY EXCEPT THAT, UNLESS OTHERWISE PROVIDED BY APPLICABLE LAW, ANY FAILURE TO MAIL SUCH COPY SHALL NOT AFFECT THE VALIDITY OF SERVICE OF PROCESS. IF ANY AGENT APPOINTED BY A PARTY REFUSES TO ACCEPT SERVICE, EACH PARTY AGREES THAT SERVICE UPON THE APPROPRIATE PARTY BY REGISTERED MAIL SHALL CONSTITUTE SUFFICIENT SERVICE. NOTHING HEREIN SHALL AFFECT THE RIGHT OF A PARTY TO SERVE PROCESS IN ANY OTHER MANNER PERMITTED BY LAW.

22. Headings. Headings are given to the sections and subsections of this Agreement solely as a convenience to facilitate reference. Such headings shall not be deemed in any way material or relevant to the construction or interpretation of this Agreement or any provision hereof.

[Signature page follows]

The Participant’s signature below indicates the Participant’s agreement with and understanding that this award is subject to all of the terms and conditions contained in the Plan and in this Agreement, and that, in the event that there are any inconsistencies between the terms of the Plan and the terms of this Agreement, the terms of the Plan shall control. The Participant further acknowledges that the Participant has read and understands the Plan and this Agreement, which contains the specific terms and conditions of this grant of Phantom Units. The Participant hereby agrees to accept as binding, conclusive and final all decisions or interpretations of the Committee upon any questions arising under the Plan or this Agreement.

	SUMMIT MIDSTREAM GP, LLC,
	a Delaware limited liability company

	By:	[ ]
	Its:	[ ]


	By:
	Name:
	Title:


	SUMMIT MIDSTREAM PARTNERS, LP,
	a Delaware limited partnership

	By:	[Summit Midstream GP, LLC]
	Its:	[General Partner]


	By:
		Name:
		Title:


	“PARTICIPANT”



	[Name]

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the use in this Registration Statement on Form S-1 of our reports dated (1) May 11, 2012 relating to the consolidated financial statements of Summit Midstream Partners, LLC and the financial statements of Summit Midstream Partners, LLC Predecessor (which report expresses an unqualified opinion and includes an explanatory paragraph related to Summit Midstream Partners, LLC’s acquisition of Grand River Gathering Company, LLC from Encana Corporation on October 27, 2011 and DFW Midstream Services LLC from Energy Future Holdings Corp., effective September 3, 2009) and (2) May 11, 2012 relating to the balance sheet of Summit Midstream Partners, LP dated May 10, 2012, appearing in the Prospectus, which is part of this Registration Statement.

We also consent to the reference to us under the heading “Experts” in such Prospectus.

/s/ Deloitte & Touche LLP

Dallas, Texas

July 17, 2012

Summit Midstream Partners, LP

Summit Midstream GP, LLC
its general partner

/s/
Name:
Title: