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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS
TABLE OF CONTENTS 3

As filed with the Securities and Exchange Commission on August 21, 2012

Registration No. 333-                        

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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

  $301,875,000   $34,595

 

(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.

   


Table of Contents

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 August 21, 2012

PROSPECTUS


LOGO

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 have applied 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 or for the twelve months ended June 30, 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 read "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

GRAPHIC


Table of Contents


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

  8

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 and the Twelve Months Ended June 30, 2012

  63

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

  67

Assumptions and Considerations

  71

Provisions of Our Partnership Agreement Relating to Cash Distributions

  77

Distributions of Available Cash

  77

Operating Surplus and Capital Surplus

  78

Capital Expenditures

  80

Subordination Period

  81

Distributions of Available Cash from Operating Surplus during the Subordination Period

  82

Distributions of Available Cash from Operating Surplus after the Subordination Period

  83

General Partner Interest and Incentive Distribution Rights

  83

Percentage Allocations of Available Cash from Operating Surplus

  84

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 Measures

  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

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Table of Contents

 
  Page

General Trends and Outlook

  100

Results of Operations—Combined Overview

  102

Liquidity and Capital Resources

  108

Quantitative and Qualitative Disclosures about Market Risk

  114

Impact of Seasonality

  115

Critical Accounting Policies and Estimates

  115

Industry Overview

  118

General

  118

Midstream Services

  118

Contractual Arrangements

  119

Market Fundamentals

  120

Business

  124

Overview

  124

Business Strategies

  126

Competitive Strengths

  127

Our Sponsors

  129

Our Assets

  129

Gas Gathering Agreements

  133

Competition

  135

Safety and Maintenance

  135

Regulation of the Oil and Natural Gas Industries

  136

Environmental Matters

  139

Title to Properties and Rights-of-Way

  145

Employees

  145

Legal Proceedings

  145

Management

  146

Management of Summit Midstream Partners, LP

  146

Director Independence

  146

Committees of the Board of Directors

  146

Directors and Executive Officers

  147

Director Compensation

  150

Executive Compensation

  150

Summary Compensation Table for 2011

  150

Outstanding Equity Awards at December 31, 2011

  153

2012 Long-Term Incentive Plan

  155

Security Ownership of Certain Beneficial Owners and Management

  158

Certain Relationships and Related Party Transactions

  161

Distributions and Payments to our General Partner and its Affiliates

  161

Agreements with Affiliates

  162

Procedures for Review, Approval and Ratification of Related-Person Transactions

  163

Conflicts of Interest and Duties

  164

Conflicts of Interest

  164

Duties of Our General Partner

  170

Description of Our Common Units

  174

The Units

  174

Transfer Agent and Registrar

  174

Transfer of Common Units

  174

The Partnership Agreement

  176

Organization and Duration

  176

Purpose

  176

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Table of Contents

 
  Page

Cash Distributions

  176

Capital Contributions

  176

Voting Rights

  177

Limited Liability

  178

Issuance of Additional Securities

  179

Amendment of Our Partnership Agreement

  180

Merger, Sale or Other Disposition of Assets

  182

Termination and Dissolution

  183

Liquidation and Distribution of Proceeds

  183

Withdrawal or Removal of Our General Partner

  183

Transfer of General Partner Interest

  185

Transfer of Ownership Interests in Our General Partner

  185

Transfer of Incentive Distribution Rights

  185

Change of Management Provisions

  185

Limited Call Right

  185

Meetings; Voting

  186

Status as Limited Partner

  187

Redemption of Ineligible Holders

  187

Indemnification

  188

Reimbursement of Expenses

  188

Books and Reports

  188

Right to Inspect Our Books and Records

  189

Registration Rights

  189

Units Eligible For Future Sale

  190

Material Federal Income Tax Consequences

  191

Partnership Status

  192

Limited Partner Status

  193

Tax Consequences of Unit Ownership

  193

Tax Treatment of Operations

  200

Disposition of Common Units

  201

Uniformity of Units

  203

Tax-Exempt Organizations and Other Investors

  204

Administrative Matters

  205

Recent Legislative Developments

  207

State, Local, Foreign and Other Tax Considerations

  208

Investment in Summit Midstream Partners, LP by Employee Benefit Plans

  209

Underwriting

  211

Validity of the Common Units

  218

Experts

  218

Where You Can Find More Information

  218

Forward-Looking Statements

  219

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

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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.

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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 June 30, 2012, our gathering systems had approximately 385 miles of pipeline and 147,600 horsepower of compression. During the first half of 2012, our systems gathered an average of approximately 909 MMcf/d of natural gas, of which approximately 64% 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.

        Substantially all of our gas gathering agreements are underpinned by areas of mutual interest, or AMIs, and minimum volume commitments, or MVCs. 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

 

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gathering systems. The minimum volume commitments, which totaled 2.5 Tcf at June 30, 2012 and, through 2020, average approximately 639 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 June 30, 2012, had a weighted average remaining life of 11.4 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 six months ended June 30, 2012, we generated $75.9 million of revenue, $16.7 million of net income and $51.5 million of Adjusted EBITDA. For the year ended December 31, 2011, we generated $103.6 million of revenue, $38.0 million of net income and $56.8 million of Adjusted EBITDA. The amounts for the year ended December 31, 2011 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 Measures."


    Our Assets and Areas of Operation

        The following table provides information regarding our assets by gathering system as of June 30, 2012, unless otherwise noted.

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

Grand River

  Mesaverde, Mancos and Niobrara     276     1,736 (2)   97,500     230,000     2,067     885     584  

DFW Midstream

  Barnett     109     311     50,100     100,000     429     410     325  
                                   

Total

        385     2,047     147,600     330,000     2,496     1,295     909  
                                   

(1)
For the six month period ended June 30, 2012.

(2)
Excludes wells connected to nine central receipt points that represent an aggregate average throughput of 255 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 $590.2 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 six months ended June 30, 2012, the Grand River system gathered an average of approximately 584 MMcf/d from five producers, including Encana as the anchor customer.

 

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        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.

        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 92 miles of pipeline to connect 62 of 73 currently identified pad sites and installing an incremental 47,600 horsepower of 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 six months ended June 30, 2012, the DFW Midstream system gathered an average of approximately 325 MMcf/d from seven 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 production data sourced from the Texas Railroad Commission, contains the most prolific wells, including the two largest and four of the top ten largest wells drilled to date in the Barnett Shale, 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, or identified to be 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 identified 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 $3.21 per MMBtu as of July 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

 

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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 that our gathering systems are well positioned to capture additional volumes from increased producer activity in these regions 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, a significant number of wells remain in various stages of completion in our AMIs and on pad sites that have already been connected to 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

 

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      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 and the six months ended June 30, 2012 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 429 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.

 

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    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 and its affiliated funds have 22 investment platforms 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 or for the twelve months ended June 30, 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

 

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      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.

 

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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 49% 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 grant $50,000 of restricted units to two of our directors pursuant to our long-term incentive plan; in addition, we will grant up to $2.5 million in phantom units with distribution equivalent rights to certain key employees (please read "Management—Executive Compensation—2012 Long-Term Incentive Plan");

    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 amended and restated 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.

 

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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

    49.0 %

LTIP Participants Restricted Units

           %

General Partner Interest

    2.0 %
       

Total

    100.0 %
       

CHART


(1)
Certain members of our management own Class B membership interests that represent net profits interests in Summit Midstream Partners, LLC through Summit Midstream Management, LLC. Please read "Security Ownership of Certain Beneficial Owners and Management."

(2)
Certain current and former employees of DFW Midstream Management LLC own Class B membership interests that represent net profits interests in DFW Midstream Services LLC. Please read "Certain Relationships and Related Party Transactions—Agreements with Affiliates—DFW Class B Membership Interests" for a description of the Class B membership interests.

 

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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 148.

        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. 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.

 

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Partnership Agreement Replacement of Fiduciary Duties

        Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the duties (including fiduciary duties) owed by the general partner to limited partners and the partnership, other than the implied contractual covenant of good faith and fair dealing. 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.

 

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        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.

 

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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 amended and restated 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.


 

 

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                        , 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

 

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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. This shortfall in cash available for distribution is due primarily to our owning the Grand River system for only two months during this period. The amount of cash available for distribution that we generated during the twelve months ended June 30, 2012 would have been sufficient to pay a cash distribution of $        per quarter ($          on an annualized basis), or approximately          % of the minimum quarterly distribution, on all common units, and would have been insufficient to make any distribution on our subordinated units for that period. This shortfall in cash available for distribution for this period is due primarily to eight months of assumed interest expense on debt we are assumed to have incurred to purchase the Grand River system.

 

 

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 September 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."

 

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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."

 

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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 have applied to list our common units on the New York Stock Exchange, or NYSE, under the symbol "SMLP."

 

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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 June 30, 2012 and for the six months ended June 30, 2012 and June 30, 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 compensation expense; and

    adjustments related to MVC shortfall payments.

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 Measures" on page 94.

 

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  Summit Midstream Predecessor   Initial
Predecessor
 
 
  Six Months Ended
June 30,
  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  
 
  (in thousands, except for volume and price amounts)
 

Statement of Operations Data:

                                     

Revenue:

                                     

Gathering services and other fees

  $ 68,647   $ 37,041   $ 91,421   $ 29,358   $ 1,714   $ 1,910  

Natural gas and condensate sales

    7,058     5,025     12,439     2,533          

Amortization of favorable and unfavorable contracts(1)

    185     (198 )   (308 )   (215 )   19      
                           

Total revenue

  $ 75,890   $ 41,868   $ 103,552   $ 31,676   $ 1,733   $ 1,910  

Costs and expenses:

                                     

Operations and maintenance

    22,717     12,795     29,855     9,503     1,147     1,010  

General and administrative

    10,796     7,375     17,476     10,035     2,939     600  

Transaction costs

    234         3,166         3,921      

Depreciation and amortization

    16,979     3,362     11,367     3,874     343     882  
                           

Total costs and expenses

    50,726     23,532     61,864     23,412     8,350     2,492  
                           

Interest (expense) income, net

    (8,154 )   (30 )   (3,042 )   32     18     (247 )

Income tax expense

    (294 )   (367 )   (695 )   (124 )   (7 )   (8 )
                           

Net income (loss)

  $ 16,716   $ 17,939   $ 37,951   $ 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

  $ 26,271   $ 379   $ 39,942   $ 9,553   $ (6,232 ) $ 595  

Investing activities

    (24,363 )   (26,475 )   (667,710 )   (153,719 )   (64,415 )   (40,777 )

Financing activities

    (9,775 )   19,394     633,809     114,132     110,102     40,182  

Balance Sheet Data (at period end):

                                     

Cash and cash equivalents

  $ 7,595         $ 15,462   $ 9,421   $ 39,455        

Trade accounts receivable

    29,217           27,476     10,238     1,373        

Property, plant, and equipment, net

    660,203           638,190     277,765     140,704        

Total assets

    1,043,417           1,030,264     340,095     215,982        

Total debt(3)

    351,209           349,893                

Other Financial Data:

                                     

EBITDA(4)

  $ 41,958   $ 21,896   $ 53,363   $ 12,353   $ (6,293 ) $ 300  

Adjusted EBITDA(4)

  $ 51,545   $ 23,837   $ 56,803   $ 12,353   $ (6,293 ) $ 300  

Capital expenditures(5)

  $ 24,363   $ 26,475   $ 78,248   $ 153,719   $ 19,519   $ 40,777  

Acquisition expenditures(6)

  $   $   $ 589,462   $   $ 44,896   $  

Operating data:

                                     

Average throughput (MMcf/d)

    909.4     303.2     432.3     135.9     23.5     15.9  

(1)
The amortization of favorable and unfavorable contracts relates to GGAs 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 June 30, 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 six months ended June 30, 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 earnings 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.

 

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(3)
Includes $202.9 million and $49.2 million of debt outstanding under our promissory notes payable to our sponsors at December 31, 2011 and June 30, 2012, respectively. On July 2, 2012, the outstanding balance under the notes was paid in full.

(4)
EBITDA and Adjusted EBITDA for the six months ended June 30, 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 the Grand River system. 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. 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 Measures."

(5)
Capital expenditures does not include acquisition capital expenditures. In addition, we historically did not make a distinction between maintenance and expansion capital expenditures; however, for the purposes of the presentation of "Partnership Unaudited Historical As Adjusted Cash Available For Distribution," we have estimated that approximately $3.1 million of these capital expenditures were maintenance capital expenditures for the year ended December 31, 2011. Please read "Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Historical as Adjusted Cash Available for Distribution for the Year Ended December 31, 2011 and the Twelve Months Ended June 30, 2012."

(6)
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.

 

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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;

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    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 or for the twelve months ended June 30, 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 June 30, 2012 would have been sufficient to pay a cash distribution of $            per quarter ($            on an annualized basis), or approximately        % of the minimum quarterly distribution, on all common units, and would have been insufficient to make any distribution on 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 September 30, 2013. We estimate that our total cash available for distribution for the twelve months ending September 30, 2013 will be approximately $95.9 million, as compared to approximately $39.9 million for the year ended December 31, 2011 and approximately $39.9 million for the twelve months ended June 30, 2012 on a historical as adjusted basis. 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 September 30, 2013 is 10% lower than our forecast, we expect we would have sufficient cash available to pay the aggregate annualized minimum quarterly distribution to holders of our common units but only        % of the aggregate annualized minimum quarterly distribution to the holders of our

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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, Energy Transfer Fuels and TOTAL accounted for approximately 34%, 17%, 12% and 10%, respectively, of our revenue for the year ended December 31, 2011. Encana, Carrizo and Chesapeake accounted for approximately 29%, 16% and 16%, respectively, of our revenue for the six months ended June 30, 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

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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 $3.21 per MMBtu as of July 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 13.9% from 55.2 Bcf/d to 62.9 Bcf/d from 2008 to 2011. Furthermore, the amount of natural gas in storage in the continental United States has increased from approximately 2.8 Tcf as of August 5, 2011 to approximately 3.2 Tcf as of August 3, 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 430 as of July 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.

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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

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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 life of the MVC contract term while also minimizing direct commodity price risk. The primary mechanism on which we rely to generate our stable cash flows is a minimum volume commitment, or MVC, from our customers. Under these 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, many of our GGAs contain provisions that allow the customer to use the excess volumes or the shortfall

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payment to credit against future excess volumes or future shortfall payments in subsequent periods. These provisions include the following:

    To the extent that a customer's throughput volumes are less than its MVC for the applicable period and the customer makes a shortfall payment, it may be entitled to an offset in one or more subsequent periods to 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 June 30, 2012, we recorded an aggregate of $7.6 million of deferred revenue 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 may be entitled to apply the excess throughput against its aggregate MVC, thereby reducing the period for which its annual MVC applies. For example, one of our DFW Midstream customers has a contracted MVC term from October 2010 through September 2017. However, this customer has regularly shipped volumes in excess of its MVCs. 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 a given period. In the most extreme circumstances we could:

    incur operating expenses with no corresponding revenues from one or more significant customers for a period of up to 35 months; or

    all or a substantial portion of our customers could cease shipping throughput volumes at a time when their respective aggregate 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

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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 outside of our AMIs. 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.

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We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties, and any material nonpayment or nonperformance by one or more of these parties could 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, 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, we do not have interconnect agreements with all of these pipelines and other facilities, including the Meeker processing plant, and the agreements we do have may be terminated in certain circumstances and on short notice. If any of these pipelines or other midstream facilities become unavailable for any reason, or, if these third parties are otherwise unwilling to receive or transport the natural gas that we gather, our revenue, cash flow and ability to make cash distributions to our unitholders could be 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. As a result, our executive management team has a limited history of operating our assets. There may be historical occurrences or

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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,

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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.

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        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 Mancos and Niobrara Shale formations, the construction will occur over an extended period of time, yet we will not receive any material increases in revenue until the project is completed and placed into service. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize or only materializes over a period materially longer than expected. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate as a result of the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not attract enough throughput to achieve our expected investment return, which could 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

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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 September 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 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. For example, in connection with our acquisition of the Grand River system, we agreed to invest capital, subject to a maximum of $200 million in any annual period, to construct the necessary facilities to support Encana's drilling program in the Mancos and Niobrara shale formations. 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.

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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;

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    enter into certain types of transactions with affiliates;

    merge or consolidate with another company or otherwise engage in a change of control; and

    transfer, sell or otherwise dispose of assets.

        Our amended and restated revolving credit facility also contains covenants requiring us to maintain certain financial ratios. Our ability 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. In addition, our credit facility contains events of default customary for credit facilities of this size and nature. Please read "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 six months ended June 30, 2012, we generated approximately 80% and 84%, 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 direct exposure to commodity price risk. Although we intend to enter into similar fee-based contracts with new customers in the future, our efforts to 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

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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

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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;

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    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

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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.

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        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

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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

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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 or 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.

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    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 interests 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

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      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

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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, other than the implied contractual covenant of good faith and fair dealing. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

    how to allocate corporate opportunities among us and its affiliates;

    whether to exercise its limited call right;

    whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;

    how to exercise its voting rights with respect to the units it owns;

    whether to exercise its registration rights;

    whether to elect to reset target distribution levels;

    whether to transfer the incentive distribution rights or any units it owns to a third party; and

    whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

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

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

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

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

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

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

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

    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."

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        Our partnership agreement provides that our conflicts committee may be comprised of one or more independent directors. If we establish a conflicts committee with only one independent director, your interests may not be as well served as if we had a conflicts committee comprised of at least two independent directors. A single-member conflicts committee would not have the benefit of discussion with, and input from, other independent directors.

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.

        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."

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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 $19.6 million for the twelve months ending September 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

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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 or group 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.

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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;

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    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."

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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 have applied 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.

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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

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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 "Material Federal Income Tax Consequences—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."

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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

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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

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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.

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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 amended and restated 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.

        As of August 20, 2012, we had $347.2 million of indebtedness outstanding under our revolving credit facility, with a weighted average interest rate of 2.76%. The amended and restated 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 amended and restated 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 amended and restated 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 amended and restated 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.

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CAPITALIZATION

        The following table shows:

    Summit Midstream Predecessor's historical cash and cash equivalents and capitalization, as of June 30, 2012; and

    our as adjusted cash and cash equivalents and capitalization, as of June 30, 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 June 30, 2012  
 
  Summit
Midstream
Predecessor
Historical
  Summit
Midstream
Partners, LP
As Adjusted
 
 
  (in thousands)
 

Cash and cash equivalents

  $ 7,595   $    
           

Long-Term Debt:

             

Revolving credit facility(1)

  $ 302,000   $    

Promissory notes payable to sponsors(2)

    49,209      
           

Total long-term debt

    351,209        
           

Membership Interests and Partners' Capital:

             

Predecessor membership interest

    658,946      

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

  $ 1,010,155   $    
           

(1)
On May 7, 2012, we amended and restated our revolving credit facility. As of August 20, 2012, the outstanding balance under our amended and restated revolving credit facility was approximately $347.2 million.

(2)
On July 2, 2012, the remaining balance outstanding under the promissory notes was paid in full.

(3)
As of June 30, 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 June 30, 2012.

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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 June 30, 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 June 30, 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

  $    
       

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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 amended and restated revolving credit facility or other debt agreements entered into in the future. Our amended and restated revolving credit facility contains financial tests and covenants that we must satisfy. Should we be unable to satisfy these restrictions, we may be prohibited from making cash distributions 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.

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    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

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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

                   

LTIP Participants Restricted Units(2)

                   

2.0% general partner interest

                   
               

Total

        $     $    
               

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

(2)
In connection with the closing of this offering, the board of directors of our general partner will grant $50,000 of restricted units to two of our directors and will grant up to $2.5 million in phantom units with distribution equivalent rights to certain key employees that provide services for us, including executive officers, pursuant to our long-term incentive plan. Please read "Management—Executive Compensation—2012 Long-Term Incentive Plan."

        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

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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                        , 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 September 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 June 30, 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 September 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 September 30, 2013.


Unaudited Historical As Adjusted Cash Available for Distribution for the Year Ended December 31, 2011 and the twelve months ended June 30, 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 $39.9 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.

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        If we had completed our initial public offering and the related transactions contemplated by this prospectus on July 1, 2011, our historical as adjusted cash available for distribution for the twelve months ended June 30, 2012, which includes eight months of operations attributable to the Grand River system, would have been approximately $39.9 million. This amount would have been sufficient to pay a cash distribution of $            per quarter ($            on an annualized basis), or approximately        % of the minimum quarterly distribution, on all of the common units, and would have been insufficient to make any distribution on our subordinated units for such period. This shortfall in cash available for distribution is due primarily to eight months of assumed interest expense on debt we are assumed to have incurred to purchase the Grand River system.

        Unaudited historical as adjusted cash available for distribution for the year ended December 31, 2011 and the twelve months ended June 30, 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 July 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 July 1, 2011.

        The following table illustrates, on a historical as adjusted basis, for the year ended December 31, 2011 and the twelve months ended June 30, 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 and July 1, 2011, respectively. Each of the adjustments presented below is explained in the footnotes to such adjustments.

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Partnership Unaudited Historical As Adjusted Cash Available for Distribution

 
  Twelve Months Ended
June 30, 2012
  Year Ended
December 31, 2011
 
 
  (in millions)
 

Net Income:(1)

  $ 36.7   $ 38.0  

Add:

             

Depreciation and amortization expense

    25.0     11.4  

Amortization of favorable and unfavorable contracts(2)

    (0.1 )   0.3  

Interest expense

    11.2     3.0  

Income tax expense(3)

    0.6     0.7  
           

EBITDA(4)

  $ 73.4   $ 53.4  

Add:

             

Adjustments related to MVC shortfall payments(5)

    8.2      

Non-cash compensation expense(6)

    2.9     3.4  
           

Adjusted EBITDA(7)(8)

  $ 84.5   $ 56.8  

Less:

             

Incremental general and administrative expenses of being a publicly traded partnership(9)

    2.5     2.5  

Cash interest expense(10)

    5.6     2.5  

Maintenance capital expenditures(11)

    4.4     3.1  

Expansion capital expenditures(11)

    661.2     664.6  

Interest on borrowings to fund expansion capital expenditures(11)

    32.1     8.8  
           

Add:

             

Borrowings to fund expansion capital expenditures(11)

    661.2     664.6  
           

Historical as Adjusted Cash Available for Distribution

  $ 39.9   $ 39.9  
           

Cash Distributions

             

Distributions per unit

  $     $    
           

Distributions to public common unitholders

  $     $    

Distributions to Summit Investments—common units

             

Distributions to Summit Investments—subordinated units

             

Distributions to LTIP participants(12)

             

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 June 30, 2012, respectively, incurred in connection with the acquisition of the Grand River system.

(2)
The amortization of favorable and unfavorable contracts relates to GGAs 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.

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(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 Measures."

(5)
Adjustments related to MVC shortfall payments account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments and (ii) our inclusion of future expected annual MVC shortfall payments in Adjusted EBITDA.

    The net increases or decreases in deferred revenue for MVC shortfall payments. 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 the contract month or year, as applicable. Under several of our GGAs, if a customer makes a shortfall payment, it may be entitled 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. Billings to customers for shortfall payment obligations are recorded as deferred revenue. For GAAP accounting purposes, we recognize deferred revenue under these arrangements in revenue once all contingencies or potential performance obligations associated with the related volumes have either (1) been satisfied through the gathering of future excess volumes of natural gas, or (2) expired (or lapsed) through the passage of time pursuant to the terms of the applicable GGA. For the purpose of calculating our cash available for distribution, shortfall payments recorded as deferred revenue for GAAP accounting purposes were recorded in Adjusted EBITDA in the period in which the cash shortfall payment was earned rather than when it was actually received.

    Our inclusion of future expected annual MVC shortfall payments in Adjusted EBITDA. Based on our historical and projected volumes, as applicable, certain of our customers made or will make, as applicable, an annual MVC shortfall payment to us that was or is payable with respect to any contract year within the applicable historical or projected financial reporting period. Note that in certain instances the actual MVC shortfall payment is received beyond the applicable historical or projected reporting periods. We included or will include a proportional amount of these historical or expected MVC shortfall payments, as the case may be, in Adjusted EBITDA each quarter prior to the quarter in which we actually receive the shortfall payment.

    For the year ended December 31, 2011 and for the twelve months ended June 30, 2012, the net increase in deferred revenue for MVCs was zero and $5.8 million, respectively. For the year ended December 31, 2011 and for the twelve months ended June 30, 2012, our inclusion of future expected annual MVC shortfall payments in Adjusted EBITDA was zero and $2.4 million, respectively.

(6)
Represents $3.4 million and $2.9 million in non-cash compensation expense that was recorded in the year ended December 31, 2011 and the twelve months ended June 30, 2012, respectively, relating to profits interests held by certain employees and members of management of our general partner and DFW Midstream Services LLC.

(7)
Represents actual historical Adjusted EBITDA for the year ended December 31, 2011 and the twelve months ended June 30, 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 Measures."

(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

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    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)
Cash interest expense does not include interest on borrowings to finance expansion capital expenditures.

(11)
For the year ended December 31, 2011 and the twelve months ended June 30, 2012, our total capital expenditures were $667.7 million and $665.6 million, respectively. $589.5 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 $4.4 million of these capital expenditures were maintenance capital expenditures for the year ended December 31, 2011 and the twelve months ended June 30, 2012, respectively. The balance of our capital expenditures for the period presented were assumed to have been expansion capital expenditures. We have assumed borrowings equal to 100% of our expansion capital expenditures to finance 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. As a result of these financing assumptions, our estimated interest expense increases from $8.8 million for the year ended December 31, 2011 to $32.1 million for the twelve months ended June 30, 2012 due to including only two months of Grand River acquisition borrowings for the year ended December 31, 2011 compared to eight months for the twelve months ended June 30, 2012.

(12)
Assumes that in connection with the closing of this offering, the board of directors of our general partner will grant $50,000 of restricted units to two of our directors and will grant up to $2.5 million in phantom units with distribution equivalent rights to certain key employees that provide services for us, including executive officers, pursuant to our long-term incentive plan. Please read "Management—Executive Compensation—2012 Long-Term Incentive Plan."


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

        We forecast that our estimated cash available for distribution for the twelve months ending September 30, 2013 will be approximately $95.9 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 September 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 September 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 September 30, 2013. However, this information is not fact and should not be relied

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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 September 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 September 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 September 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.

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Estimated Cash Available for Distribution

 
  Twelve Months
Ending
September 30, 2013
 
 
  (in millions)
 

Revenues

       

Gathering services and other fees

  $ 150.8  

Natural gas and condensate sales

    14.0  

Amortization of favorable and unfavorable contracts(1)

    (1.6 )
       

Total revenues

  $ 163.2  

Costs and Expenses

       

Operations and maintenance

    51.0  

General and administrative

    21.1  

Depreciation and amortization

    37.2  
       

Total costs and expenses

    109.3  

Interest expense

    9.3  

Income tax expense(2)

    0.6  
       

Net Income

  $ 44.0  

Adjustments to reconcile net income to Estimated Adjusted EBITDA:

       

Add:

       

Depreciation and amortization expense

    37.2  

Amortization of favorable and unfavorable contracts(1)

    1.6  

Interest expense

    9.3  

Income tax expense

    0.6  
       

EBITDA(3)

  $ 92.7  

Add:

       

Adjustments related to MVC shortfall payments(4)

    14.6  

Non-cash compensation expense(5)

    1.8  
       

Estimated Adjusted EBITDA(6)

  $ 109.1  

Adjustments to reconcile Estimated Adjusted EBITDA to Estimated Cash Available for Distribution:

       

Less:

       

Cash interest expense

    7.7  

Expansion capital expenditures

    43.3  

Maintenance capital expenditures

    5.5  

Add:

       

Borrowings to fund expansion capital expenditures

    43.3  
       

Estimated Cash Available for Distribution

  $ 95.9  

Distributions to public common unitholders

  $    

Distributions to Summit Investments—common units

       

Distributions to Summit Investments—subordinated units

       

Distributions to LTIP participants(7)

       

Distributions to our general partner

       

Total annualized minimum quarterly distributions

  $    

Excess of cash available for distribution over aggregate annualized minimum annual cash distributions(8)

  $    

(1)
The amortization of favorable and unfavorable contracts relates to GGAs that were deemed to be above or below market on September 3, 2009, the date of the acquisition of the DFW Midstream

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    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 Measures."

(4)
Adjustments related to MVC shortfall payments account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments and (ii) our inclusion of future expected annual MVC shortfall payments in Adjusted EBITDA.

    The net increases or decreases in deferred revenue for MVC shortfall payments. 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 the contract month or year, as applicable. Under several of our GGAs, if a customer makes a shortfall payment, it may be entitled 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. Billings to customers for shortfall payment obligations are recorded as deferred revenue. For GAAP accounting purposes, we recognize deferred revenue under these arrangements in revenue once all contingencies or potential performance obligations associated with the related volumes have either (1) been satisfied through the gathering of future excess volumes of natural gas, or (2) expired (or lapsed) through the passage of time pursuant to the terms of the applicable GGA. For the purpose of calculating our cash available for distribution, we have assumed that shortfall payments recorded as deferred revenue for GAAP accounting purposes are recorded in Adjusted EBITDA in the period in which the cash shortfall payment is earned rather than when it is actually received.

    Our inclusion of future expected annual MVC shortfall payments in Adjusted EBITDA. Based on our volume projections, certain of our customers will make an annual MVC shortfall payment to us both within the forecast period and in December 2013, which is beyond the forecast period. We will include a proportional amount of these expected MVC shortfall payments in Adjusted EBITDA each quarter prior to the quarter in which we actually receive the shortfall payment. We do not anticipate funding any portion of our quarterly distribution related to the inclusion of the MVC shortfall payment within Adjusted EBITDA prior to the actual receipt of payment with working capital borrowings during the forecast period.


For the twelve months ending September 30, 2013, our adjustments related to MVC shortfall payments include $9.4 million associated with the expected change in deferred revenue and $5.2 million associated with our inclusion of future expected annual MVC shortfall payments in Adjusted EBITDA.

(5)
Represents $1.8 million in non-cash compensation expense expected to occur during the twelve months ending September 30, 2013 relative to profits interests held by certain employees and members of management of our general partner and DFW Midstream Services LLC.

(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 Measures."

(7)
Assumes that in connection with the closing of this offering, the board of directors of our general partner will grant $50,000 of restricted units to two of our directors and will grant up to $2.5 million in phantom units with distribution equivalent rights to certain key employees that provide

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    services for us, including executive officers, pursuant to our long-term incentive plan. Please read "Management—Executive Compensation—2012 Long-Term Incentive Plan."

(8)
Includes $5.2 million of cash to be received outside the forecast period with respect to MVC shortfall payments. Please read footnote (4) above.


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 September 30, 2013.


    General Considerations

        As discussed further below, a significant portion of the increase in cash available for distribution for the twelve months ending September 30, 2013 as compared to the year ended December 31, 2011 and the twelve months ended June 30, 2012 is attributable to additional revenues that we expect to generate under gas gathering agreements related to our Grand River system and to a decrease in interest expense as compared to the assumed interest expense related to assumed borrowings to finance historical capital expenditures. 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.

        We estimate that we will generate revenue of $163.2 million for the twelve months ending September 30, 2013, compared to $103.6 million for the year ended December 31, 2011 and $137.6 million for the twelve months ended June 30, 2012. The significant increase in revenue for the forecast period as compared to the year ended December 31, 2011 and the twelve months ended June 30, 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 eight months for the twelve months ended June 30, 2012. Approximately 46% of our projected revenue is expected to be generated from our Grand River system and approximately 54% is expected to be generated from our DFW Midstream system for the twelve month period ending September 30, 2013. Approximately 87% of our revenue is associated with fee-based gathering services that we provide to our customers. Approximately 9% 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 927 MMcf/d for the twelve months ending September 30, 2013. This compares to our average daily throughput in the first half of 2012 of approximately 909 MMcf/d and an average of 432 MMcf/d for the year ended December 31, 2011 and 733 MMcf/d for the twelve months ended June 30, 2012. This expected increase in volumes in the forecast period as compared to the year ended December 31, 2011 and the twelve months ended June 30, 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 half of 2012 was approximately 584 MMcf/d. We expect throughput will average approximately 581 MMcf/d for the twelve months ending September 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

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        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 September 30, 2013 compares to aggregate minimum volume commitments of 483 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 587 MMcf/d for the eight months ended June 30, 2012.

      DFW Midstream volumes. Our average daily throughput on the DFW Midstream system in the first half of 2012 was approximately 325 MMcf/d. We expect throughput on the DFW Midstream system will average approximately 346 MMcf/d for the twelve months ending September 30, 2013, primarily based on our recent addition of a new customer, Beacon E&P Company, LLC, or Beacon E&P, and our assumption that in the aggregate, our other 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 September 30, 2013 compares to aggregate minimum volume commitments of 175 MMcf/d from our DFW Midstream customers over the same time period and average throughput of 333 MMcf/d for the year ended December 31, 2011 and 343 MMcf/d for the twelve months ended June 30, 2012.

    Fees.  We estimate that we will receive an average gathering fee of $0.42 per Mcf for the twelve months ending September 30, 2013, compared to $0.53 per Mcf for the year ended December 31, 2011 and $0.42 per Mcf for the twelve months ended June 30, 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 in line with the twelve months ended June 30, 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 entire 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 June 30, 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 $0.31 per Mcf for the twelve months ending September 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 June 30, 2012 were $0.60 per Mcf and $0.58 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 September 30, 2013.

    Natural Gas and Condensate Sales.  Approximately 9% of our projected revenue in the twelve months ending September 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 August 13, 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 August 13, 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 8.7 MMcf/d of natural gas at $3.35 per MMBtu for the twelve months ending September 30, 2013, compared to 9.5 MMcf/d of natural gas at $3.60 per MMBtu for the year ended December 31, 2011 and 12.0 MMcf/d of

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      natural gas at $2.84 per MMBtu for the twelve months ended June 30, 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 116 Bbls/d of condensate at $83 per Bbl for the twelve months ending September 30, 2013, compared to 20 Bbls/d of condensate at $85 per Bbl for the year ended December 31, 2011 and 84 Bbls/d of condensate at $89 per Bbl for the twelve months ended June 30, 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 September 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 September 30, 2013 was 10% lower than our forecast, we would have sufficient cash available to pay the aggregate annualized minimum quarterly distribution to holders of our common units but 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 $51.0 million for the twelve months ending September 30, 2013, compared to operating and maintenance expenses of $29.9 million for the year ended December 31, 2011 and $39.8 million for the twelve months ended June 30, 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 $13.1 million, or $0.10 per Mcf, for the twelve months ending September 30, 2013, compared to compression costs of $13.4 million, or $0.11 per Mcf, for the year ended December 31, 2011 and $12.2 million, or $0.10 per Mcf, for the twelve months ended June 30, 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 $37.8 million, or $0.11 per Mcf, for the twelve months ending September 30, 2013, compared to operating and maintenance expenses of $16.5 million, or $0.10 per Mcf, for the year ended December 31, 2011 and $27.6 million, or $0.10 per Mcf, for the twelve months ended June 30, 2012. Increased aggregate operating and maintenance expenses for the twelve months ending September 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 June 30, 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. We also expect slightly higher operating and maintenance expenses, net of compression costs, primarily due to the hiring of additional operations personnel dedicated to the DFW Midstream system and the Grand River system. Given our volume projections, we expect these increased personnel costs, together with our inflation assumptions for the twelve months ending September 30, 2013, will lead to increased operating and maintenance expenses, net of compression costs, on a dollar per Mcf basis.

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    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 $21.1 million for the twelve months ending September 30, 2013. This compares to $17.5 million for the year ended December 31, 2011 and $20.9 million for the twelve months ended June 30, 2012. The year ended December 31, 2011 and the twelve months ended June 30, 2012 include certain non-cash, and non-recurring costs that we do not expect to incur in the forecast period, such as one-time, non-cash compensation expense adjustments, transition service expenses associated with our acquisition of the Grand River system from Encana in October 2011, and a higher level of acquisition activity and greenfield diligence expenses incurred in transactions that did not close. Excluding all non-cash compensation, and any non-recurring costs, general and administrative expenses are expected to total $19.3 million for the twelve months ending September 30, 2013, compared with $12.8 million for the year ended December 31, 2011 and $15.4 million for the twelve months ended June 30, 2012. The primary drivers of the increase in our recurring general and administrative expenses for the twelve months ending September 30, 2013, are (i) the inclusion of a full year of general and administrative expenses associated with our acquisition of the Grand River system, including the associated expense of hiring our Grand River asset management and other corporate personnel, and (ii) approximately $2.5 million of incremental expenses related to being a publicly traded partnership.


    Depreciation and Amortization Expense

        We estimate that depreciation and amortization expense for the twelve months ending September 30, 2013 will be $37.2 million, compared to $11.4 million for the year ended December 31, 2011 and $25.0 million for the twelve months ended June 30, 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 September 30, 2013 will be $48.8 million, compared to $667.7 million for the year ended December 31, 2011 and $665.6 million for the twelve months ended June 30, 2012. $590.2 million of our capital expenditures for the year ended December 31, 2011 and the twelve months ended June 30, 2012 were related to the acquisition of the Grand River system in October 2011. 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 $21.3 million for the twelve months ending September 30, 2013, which will account for approximately 44% 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 $5.5 million for

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      maintenance capital expenditures for the twelve months ending September 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, including certain 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 September 30, 2013 will total $43.3 million, of which approximately $18.9 million are attributable to the Grand River system and approximately $24.3 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 during the twelve months ending September 30, 2013 will be to construct new low-pressure pipeline laterals to connect identified pad sites for our customers, including five pad sites adjacent to the DFW Midstream system for our new customer, Beacon E&P. We are also forecasting expansion capital expenditures during the twelve months ending September 30, 2013 of approximately $5.3 million to install additional compression assets and to complete the construction of several looping pipelines on the DFW Midstream system to increase system capacity to over 450 MMcf/d and to optimize throughput hydraulics and operating pressures.


    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;

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      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 amended and restated 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 September 30, 2013 will be approximately $7.7 million, compared to $2.5 million for the year ended December 31, 2011 and $10.1 million for the twelve months ended June 30, 2012. The interest expense for these historical periods does not include assumed interest expense related to assumed borrowings to finance capital expenditures. Our projected interest expense is based on an assumed average outstanding debt balance of $207.0 million under our amended and restated revolving credit facility during the forecasted period, including borrowings to finance our projected expansion capital expenditures. We assume a weighted average interest rate of 2.92% during the twelve months ending September 30, 2013. This rate is based on a forecast of LIBOR rates during the period plus the applicable margin as defined in our amended and restated credit agreement. We have also assumed commitment fees of 0.50% for the unused portion of our amended and restated 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 September 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).

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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

        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; or

    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

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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 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 common or subordinated units that it owns. Please read "—General Partner Interest and Incentive Distribution Rights" for additional information.


Operating Surplus and Capital Surplus

        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

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      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.

        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 and (iv) capital contributions received.

        We define operating expenditures as all of our cash expenditures, including, but not limited to, taxes, compensation of employees, officers and directors of our general partner, 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), and repayment of working capital borrowings; 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;

    payment of transaction expenses (including, but not limited to, taxes) relating to interim capital transactions;

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    distributions to our partners; or

    repurchases of our units, other than repurchases to satisfy obligations under employee benefit plans or reimbursement of expenses of our general partner for purchases of units to satisfy obligations under employee benefit plans.


    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.

        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.

        Capital expenditures that are made in part for maintenance capital purposes and in part for expansion capital purposes will be allocated between maintenance capital expenditures and expansion capital expenditures by our general partner.

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Subordination Period

        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

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    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;

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    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 at any time without the approval of any person.

        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

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    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,

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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.

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        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
   
 
 
  Quarterly Distribution per
Unit 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

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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
   
 
 
  Quarterly Distribution per
Unit 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 distributions 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

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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

        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.

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        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.

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        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.

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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 June 30, 2012 and for the six months ended June 30, 2012 and June 30, 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.

        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 compensation expense; and

    adjustments related to MVC shortfall payments.

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 94. For a description of adjustments related to MVC shortfall payments, please read "Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Historical As Adjusted Cash Available for Distribution for the Year Ended December 31, 2011 and the Twelve Months Ended June 30, 2012."

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  Summit Midstream Predecessor    
 
 
  Initial Predecessor  
 
  Six Months Ended
June 30,
   
   
   
 
 
  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  
 
  (in thousands, except for volume and price amounts)
 

Statement of Operations Data:

                                     

Revenue:

                                     

Gathering services and other fees

  $ 68,647   $ 37,041   $ 91,421   $ 29,358   $ 1,714   $ 1,910  

Natural gas and condensate sales

    7,058     5,025     12,439     2,533          

Amortization of favorable and unfavorable contracts(1)

    185     (198 )   (308 )   (215 )   19      
                           

Total revenue

  $ 75,890   $ 41,868   $ 103,552   $ 31,676   $ 1,733   $ 1,910  

Costs and expenses:

                                     

Operations and maintenance

    22,717     12,795     29,855     9,503     1,147     1,010  

General and administrative

    10,796     7,375     17,476     10,035     2,939     600  

Transaction costs

    234         3,166         3,921      

Depreciation and amortization

    16,979     3,362     11,367     3,874     343     882  
                           

Total costs and expenses

    50,726     23,532     61,864     23,412     8,350     2,492  
                           

Interest (expense) income, net

    (8,154 )   (30 )   (3,042 )   32     18     (247 )

Income tax expense

    (294 )   (367 )   (695 )   (124 )   (7 )   (8 )
                           

Net income (loss)

  $ 16,716   $ 17,939   $ 37,951   $ 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

  $ 26,271   $ 379   $ 39,942   $ 9,553   $ (6,232 ) $ 595  

Investing activities

    (24,363 )   (26,475 )   (667,710 )   (153,719 )   (64,415 )   (40,777 )

Financing activities

    (9,775 )   19,394     633,809     114,132     110,102     40,182  

Balance Sheet Data (at period end):

                                     

Cash and cash equivalents

  $ 7,595         $ 15,462   $ 9,421   $ 39,455        

Trade accounts receivable

    29,217           27,476     10,238     1,373        

Property, plant, and equipment, net

    660,203           638,190     277,765     140,704        

Total assets

    1,043,417           1,030,264     340,095     215,982        

Total debt(3)

    351,209           349,893                

Other Financial Data:

                                     

EBITDA(4)

  $ 41,958   $ 21,896   $ 53,363   $ 12,353   $ (6,293 ) $ 300  

Adjusted EBITDA(4)

  $ 51,545   $ 23,837   $ 56,803   $ 12,353   $ (6,293 ) $ 300  

Capital expenditures(5)

  $ 24,363   $ 26,475   $ 78,248   $ 153,719   $ 19,519   $ 40,777  

Acquisition expenditures(6)

  $   $   $ 589,462   $   $ 44,896   $  

Operating data:

                                     

Average throughput (MMcf/d)

    909.4     303.2     432.3     135.9     23.5     15.9  

(1)
The amortization of favorable and unfavorable contracts relates to GGAs 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.

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(2)
The pro forma earnings per common unit gives effect to the recapitalization transactions as of December 31, 2011 and June 30, 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 six months ended June 30, 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 earnings 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 $49.2 million of debt outstanding under our promissory notes payable to our sponsors at December 31, 2011 and June 30, 2012, respectively. On July 2, 2012, the outstanding balance under the notes was paid in full.

(4)
EBITDA and Adjusted EBITDA for the six months ended June 30, 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 the Grand River system. 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. For a reconciliation to our most directly comparable financial measures calculated and presented in accordance with GAAP, please read "—Non-GAAP Financial Measures."

(5)
Capital expenditures does not include acquisition capital expenditures. In addition, we historically did not make a distinction between maintenance and expansion capital expenditures; however, for the purposes of the presentation of "Partnership Unaudited Historical As Adjusted Cash Available For Distribution," we have estimated that approximately $3.1 million of these capital expenditures were maintenance capital expenditures for the year ended December 31, 2011. Please read "Our Cash Distribution Policy and Restrictions on Distributions—Partnership Unaudited Historical As Adjusted Cash Available For Distribution."

(6)
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 Measures

        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.

        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 compensation expense; and

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      adjustments related to MVC shortfall payments.

        EBITDA and Adjusted EBITDA are used as supplemental financial measures by 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.

        (Adjusted EBITDA)

    the financial performance of our assets without regard to the impact of the timing of MVC shortfall payments under our GGAs or the impact of non-cash compensation expense.

        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.

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

 
   
   
   
   
   
 
 
  Summit Midstream Predecessor   Initial
Predecessor
 
 
  Six Months Ended
June 30,
  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  
 
  (in thousands, except for volume and price amounts)
 

Reconciliation of EBITDA
and Adjusted EBITDA to Net Income (Loss)

                                     

Net Income (Loss)

  $ 16,716   $ 17,939   $ 37,951   $ 8,172   $ (6,606 ) $ (837 )

Add:

                                     

Interest expense

    8,160     38     3,054             247  

Income tax expense

    294     367     695     124     7     8  

Depreciation and amortization expense

    16,979     3,362     11,367     3,874     343     882  

Amortization of favorable and unfavorable contracts

    (185 )   198     308     215     (19 )    

Less:

                                     

Interest income

    6     8     12     32     18      
                           

EBITDA

  $ 41,958   $ 21,896   $ 53,363   $ 12,353   $ (6,293 ) $ 300  
                           

Add:

                                     

Non-cash compensation expense

  $ 1,412   $ 1,941   $ 3,440   $   $   $  

Adjustments related to MVC shortfall payments(1)

    8,175                      
                           

Adjusted EBITDA(2)

  $ 51,545   $ 23,837   $ 56,803   $ 12,353   $ (6,293 ) $ 300  
                           

 

 
   
   
   
   
   
 
 
  Summit Midstream Predecessor   Initial
Predecessor
 
 
  Six Months Ended
June 30,
  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  
 
  (in thousands, except for volume and price amounts)
 

Reconciliation of EBITDA and Adjusted EBITDA to Net Cash Flows Provided by (Used In) Operating Activities

                                     

Net Cash Flows Provided by (Used In) Operating Activities

  $ 26,271   $ 379   $ 39,942   $ 9,553   $ (6,232 ) $ 595  

Add:

                                     

Interest expense(3)

    2,167     (51 )   469             247  

Income tax expense

    294     367     695     124     7     8  

Changes in operating assets and liabilities

    14,644     23,150     15,709     2,708     (50 )   (550 )

Less:

                                     

Non-cash compensation expense

    1,412     1,941     3,440              

Interest income

    6     8     12     32     18      
                           

EBITDA(2)

  $ 41,958   $ 21,896   $ 53,363   $ 12,353   $ (6,293 ) $ 300  
                           

Add:

                                     

Non-cash compensation expense

  $ 1,412   $ 1,941   $ 3,440   $   $   $  

Adjustments related to MVC shortfall payments(1)

    8,175                      
                           

Adjusted EBITDA(2)

  $ 51,545   $ 23,837   $ 56,803   $ 12,353   $ (6,293 ) $ 300  
                           

(1)
For a discussion of adjustments related to shortfall payments, please read "Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Historical As Adjusted Cash Available for Distribution for the Year Ended December 31, 2011 and the Twelve Months Ended June 30, 2012."

(2)
EBITDA and Adjusted EBITDA for the six months ended June 30, 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 the Grand River system. 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.

(3)
Interest expense presented excludes $0.6 million, $0.6 million and $0.1 million in amortization of deferred loan costs for the year ended December 31, 2011 and for the six months ended June 30, 2012 and 2011, respectively. Interest expense excludes $2.0 million and $5.4 million in paid in kind interest on promissory notes payable to our sponsors for the year ended December 31, 2011 and for the six months ended June 30, 2012, respectively.

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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

        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 June 30, 2012, our gathering systems had approximately 385 miles of pipeline and 147,600 horsepower of compression. During the six months ended June 30, 2012, our systems gathered an average of approximately 909 MMcf/d of natural gas, of which approximately 64% contained natural gas liquids, or NGLs, that were extracted by a third party processor.

        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 natural gas producing wells drilled by our customers within the AMIs will be shipped on our gathering systems. The minimum volume commitments, which totaled 2.5 Tcf at June 30, 2012 and, through 2020, average approximately 639 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 June 30, 2012, had a weighted average remaining life of 11.4 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 six months ended June 30, 2012, approximately 80% and 84%, 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

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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 eight, 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 that our gathering systems are well positioned to capture additional volumes from increased producer activity in these regions 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.

        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, a significant number of wells

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remain in various stages of completion in our AMIs and on pad sites that have already been connected to 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,

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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. The majority of our compressors in the Barnett Shale are electric driven and power costs are directly correlated to the run-time of these compressors, which depends directly on the volume of natural gas gathered. As part of our contracts with our 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 compensation expense and adjustments related to MVC shortfall payments. Please read "Selected Historical Financial and Operating Data—Non-GAAP Financial Measures." 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 financial 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.

    (Adjusted EBITDA)

    the financial performance of our assets without regard to the impact of the timing of MVC shortfall payments under our GGAs or the impact of non-cash compensation expense.

    (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.

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    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 Measures."


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 $3.21 per MMBtu as of July 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 13.9% from 55.2 Bcf/d to 62.9 Bcf/d from 2008 to 2011. Over the same time period, natural gas consumption increased only 4.5% to 66.6 Bcf/d. Furthermore, the amount of natural gas in storage in the continental United States has increased from approximately 2.8 Tcf as of August 5, 2011 to approximately 3.2 Tcf as of August 3, 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 430 as of July 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, 49% of the electricity in the United States was generated by coal-fired power plants and in December 2011, 39% of the electricity in the United States was generated by coal-fired power plants. In January 2012, the EIA projected total annual domestic

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consumption of natural gas to increase from approximately 22.9 Tcf in 2009 to approximately 26.6 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 27.9 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.


    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 27.9 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    
 
 
  Initial Predecessor  
 
  Six Months Ended
June 30,
   
   
   
 
 
  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  
 
  (in thousands, except for volume and price amounts)
 

Statement of Operations Data:

                                     

Revenue:

                                     

Gathering services and other fees

  $ 68,647   $ 37,041   $ 91,421   $ 29,358   $ 1,714   $ 1,910  

Natural gas and condensate sales

    7,058     5,025     12,439     2,533          

Amortization of favorable and unfavorable contracts(1)

    185     (198 )   (308 )   (215 )   19      
                           

Total revenue

  $ 75,890   $ 41,868   $ 103,552   $ 31,676   $ 1,733   $ 1,910  

Costs and expenses:

                                     

Operations and maintenance

    22,717     12,795     29,855     9,503     1,147     1,010  

General and administrative

    10,796     7,375     17,476     10,035     2,939     600  

Transaction costs

    234         3,166         3,921      

Depreciation and amortization

    16,979     3,362     11,367     3,874     343     882  
                           

Total costs and expenses

    50,726     23,532     61,864     23,412     8,350     2,492  
                           

Interest (expense) income, net

    (8,154 )   (30 )   (3,042 )   32     18     (247 )