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As filed with the Securities and Exchange Commission on October 22, 2012

Registration No. 333-180841

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



Amendment No. 7
to
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933



Southcross Energy Partners, L.P.
(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)
  45-5045230
(I.R.S. Employer
Identification Number)

1700 Pacific Avenue
Suite 2900
Dallas, Texas 75201
(214) 979-3700

(Address, including Zip Code, and Telephone Number, including
Area Code, of Registrant's Principal Executive Offices)

David W. Biegler
President and Chief Executive Officer
1700 Pacific Avenue
Suite 2900
Dallas, Texas 75201
(214) 979-3700

(Name, Address, including Zip Code, and Telephone Number,
including Area Code, of Agent for Service)



Copies to:
William N. Finnegan IV
Ryan J. Maierson
Latham & Watkins LLP
811 Main Street,
Suite 3700
Houston, Texas 77002
(713) 546-5400
  Douglass M. Rayburn
Joshua Davidson
Baker Botts L.L.P.
2001 Ross Avenue
Dallas, Texas 75201
(214) 953-6500



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

         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, as amended, 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 preliminary 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 preliminary 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 OCTOBER 22, 2012

P R E L I M I N A R Y    P R O S P E C T U S

GRAPHIC

9,000,000 Common Units
Representing Limited Partner Interests
Southcross Energy Partners, L.P.

          This is the initial public offering of our common units representing limited partner interests. We are offering 9,000,000 common units in this offering. We currently expect that the initial public offering price will be between $19.00 and $21.00 per common unit. Prior to this offering, there has been no public market for our common units.

          We have granted the underwriters an option to purchase up to 1,350,000 additional common units. We have been approved to list our common units on the New York Stock Exchange, subject to official notice of issuance, under the symbol "SXE."

          Investing in our common units involves risks. Please read "Risk Factors" beginning on page 19.

          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.

    Because of the natural decline in production from existing wells in our areas of operation, our success depends in part on producers replacing declining production and also on our ability to obtain new sources of natural gas. Any decrease in the volumes of natural gas that we gather, compress, process, treat or transport or in the volumes of natural gas liquids, or NGLs, that we fractionate or transport could adversely affect our business and operating results.

    Natural gas and NGL prices are volatile, and a change in these prices in absolute terms, or an adverse change in the prices of natural gas and NGLs relative to one another, could adversely affect our gross operating margin and cash flow and our ability to make cash distributions to our unitholders.

    Downtime associated with our assets or third-party assets interconnected with our assets could have a material adverse effect on our business and operating results.

    Southcross Energy LLC, or Holdings, 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. Holdings 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.

    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.

    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.

    You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

          We are an emerging growth company and are eligible for reduced reporting requirements. See "Summary—Implications of Being an Emerging Growth Company."

          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.

 
  Per Common Unit   Total
Initial Public Offering Price   $   $
Underwriting Discounts and Commissions(1)   $   $
Proceeds to Southcross Energy Partners, L.P. (before expenses)   $   $

(1)
Excludes an aggregate structuring fee payable to Citigroup Global Markets Inc. and Wells Fargo Securities, LLC that is equal to 0.40% of the gross proceeds of this offering. Please see "Underwriting." The structuring fee will be paid to Citigroup Global Markets Inc. and Wells Fargo Securities, LLC from the net proceeds of this offering. Please see "Use of Proceeds."

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

Joint Book-Running Managers
Citigroup       Wells Fargo Securities
Barclays       J.P. Morgan

Co-Managers

 

 

 

 

 
RBC Capital Markets       Raymond James
Baird   Stifel Nicolaus Weisel   SunTrust Robinson Humphrey

   

                        , 2012


Table of Contents

MAP


Table of Contents


TABLE OF CONTENTS

 
  Page

Summary

  1

Southcross Energy Partners, L.P. 

  1

Overview

  1

Our Growth Drivers

  2

Business Strategies

  3

Competitive Strengths

  4

Our Sponsor

  5

Risk Factors

  5

Recapitalization Transactions and Partnership Structure

  7

Ownership of Southcross Energy Partners, L.P. 

  8

Our Management

  9

Principal Executive Offices and Internet Address

  9

Summary of Conflicts of Interest and Duties

  10

Implications of Being an Emerging Growth Company

  10

The Offering

  12

Summary Historical and Pro Forma Financial and Operating Data

  17

Risk Factors

  19

Risks Related to our Business

  19

Risks Inherent in an Investment in Us

  37

Tax Risks

  47

Use of Proceeds

  52

Capitalization

  53

Dilution

  54

Our Cash Distribution Policy and Restrictions on Distributions

  55

General

  55

Our Minimum Quarterly Distribution

  57

Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2011 and the Twelve Months Ended June 30, 2012

  59

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

  61

Assumptions and Considerations

  64

Provisions of Our Partnership Agreement Relating to Cash Distributions

  71

Distributions of Available Cash

  71

Operating Surplus and Capital Surplus

  72

Capital Expenditures

  74

Subordination Period

  75

Distributions of Available Cash from Operating Surplus during the Subordination Period

  76

Distributions of Available Cash from Operating Surplus after the Subordination Period

  77

General Partner Interest and Incentive Distribution Rights

  77

Percentage Allocations of Available Cash from Operating Surplus

  78

General Partner's Right to Reset Incentive Distribution Levels

  78

Distributions from Capital Surplus

  81

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

  82

Distributions of Cash Upon Liquidation

  82

Selected Historical and Pro Forma Financial and Operating Data

  85

Non-GAAP Financial Measures

  86

Management's Discussion and Analysis of Financial Condition and Results of Operations

  90

Overview

  90

Our Operations

  90

How We Evaluate Our Operations

  92

General Trends and Outlook

  98

Results of Operations—Combined Overview

  100

Liquidity and Capital Resources

  107

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  Page

Off-Balance Sheet Arrangements

  110

Capital Requirements

  110

Integrity Management

  111

Distributions

  111

Our Credit Facility

  111

Credit Risk and Customer Concentration

  113

Contractual Obligations

  113

Quantitative and Qualitative Disclosures about Market Risk

  114

Impact of Seasonality

  114

Critical Accounting Policies and Estimates

  114

Industry Overview

  116

General

  116

Midstream Services

  116

U.S. Natural Gas Fundamentals

  117

U.S. Natural Gas Liquids Fundamentals

  118

Business

  120

Overview

  120

Our Growth Drivers

  121

Business Strategies

  123

Competitive Strengths

  125

Our Sponsor

  126

Our Assets

  127

Competition

  133

Safety and Maintenance

  133

Regulation of Operations

  135

Environmental Matters

  139

Title to Properties and Rights-of-Way

  144

Employees

  144

Legal Proceedings

  144

Management

  145

Management of Southcross Energy Partners, L.P. 

  145

Director Independence

  145

Committees of the Board of Directors

  145

Directors and Executive Officers

  146

Executive Compensation

  150

Security Ownership of Certain Beneficial Owners and Management

  161

Certain Relationships and Related Party Transactions

  163

Distributions and Payments to our General Partner and its Affiliates

  163

Agreements Governing the Transactions

  164

Agreements with Affiliates

  165

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

  166

Conflicts of Interest and Duties

  167

Conflicts of Interest

  167

Duties of Our General Partner

  173

Description of Our Common Units

  176

The Units

  176

Transfer Agent and Registrar

  176

Transfer of Common Units

  176

The Partnership Agreement

  178

Organization and Duration

  178

Purpose

  178

Cash Distributions

  178

Capital Contributions

  178

Voting Rights

  179

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  Page

Limited Liability

  180

Issuance of Additional Securities

  181

Amendment of Our Partnership Agreement

  182

Merger, Sale or Other Disposition of Assets

  184

Termination and Dissolution

  184

Liquidation and Distribution of Proceeds

  185

Withdrawal or Removal of Our General Partner

  185

Transfer of General Partner Interest

  186

Transfer of Ownership Interests in Our General Partner

  187

Transfer of Incentive Distribution Rights

  187

Change of Management Provisions

  187

Limited Call Right

  187

Meetings; Voting

  187

Status as Limited Partner

  188

Non-Citizen Assignees; Redemption

  188

Non-Taxpaying Assignees; Redemption

  189

Indemnification

  189

Reimbursement of Expenses

  190

Books and Reports

  190

Right to Inspect Our Books and Records

  190

Registration Rights

  191

Units Eligible For Future Sale

  192

Material Federal Income Tax Consequences

  193

Partnership Status

  194

Limited Partner Status

  195

Tax Consequences of Unit Ownership

  195

Tax Treatment of Operations

  202

Disposition of Common Units

  203

Uniformity of Units

  205

Tax-Exempt Organizations and Other Investors

  206

Administrative Matters

  207

Recent Legislative Developments

  209

State, Local, Foreign and Other Tax Considerations

  210

Investment in Southcross Energy Partners, L.P. by Employee Benefit Plans

  211

Underwriting

  213

Validity of the Common Units

  219

Experts

  219

Where You Can Find More Information

  219

Forward-Looking Statements

  220

Index to Financial Statements

  F-1

Appendix A—First Amended and Restated Agreement of Limited Partnership of Southcross Energy Partners,  L.P.

  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 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.

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Industry and Market Data

        The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data is also based on our good faith estimates. Although we believe these third-party sources are reliable and that the information is accurate and complete, we have not independently verified the information.

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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 $20.00 per common unit (the midpoint of the price range set forth on the cover of this prospectus) 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 19 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 "Southcross Energy Partners, L.P.," the "partnership," "we," "our," "us" or like terms (i) for periods prior to August 1, 2009, the effective date of Southcross Energy LLC's acquisition of our initial assets from Crosstex Energy, L.P., or "Crosstex," refer to the entities and assets we acquired from Crosstex, which we refer to as the Southcross Energy Predecessor, or our "Predecessor," and (ii) for periods from and after August 1, 2009, refer to Southcross Energy Partners, L.P. and its subsidiaries after giving effect to the recapitalization transactions described under "—Recapitalization Transactions and Partnership Structure" on page 7 of this prospectus. References to "Southcross Energy Partners GP" or our "general partner" refer to Southcross Energy Partners GP, LLC, a Delaware limited liability company and our general partner, references to "Charlesbank" refer to Charlesbank Capital Partners, LLC and its affiliated investment funds, and references to "Holdings" refer to Southcross Energy LLC, a Delaware limited liability company owned by Charlesbank and certain members of our management team. References to "EAI" refer to Enterprise Alabama Intrastate, LLC, an intrastate pipeline and gathering system in Alabama that we acquired from a subsidiary of Enterprise Products Partners L.P. effective September 1, 2011. We include as Appendix B a glossary of some of the terms we use in this prospectus.


Southcross Energy Partners, L.P.

Overview

        We are a growth-oriented limited partnership that was formed by members of our management team and Charlesbank to own, operate, develop and acquire midstream energy assets. We provide natural gas gathering, processing, treating, compression and transportation services and natural gas liquids, or NGLs, fractionation and transportation services for our producer customers, primarily under fixed-fee and fixed-spread contracts, and we also source, purchase, transport and sell natural gas and NGLs to our power generation, industrial and utility customers primarily under fixed-spread contracts. Our assets are located in South Texas, Mississippi and Alabama. Our South Texas assets operate in or within close proximity to the Eagle Ford shale region, which has experienced a strong increase in investment and drilling activity by exploration and production companies in recent years. Based on industry data compiled by Smith Bits, a subsidiary of Smith International, Inc., approximately 14.4% of all drilling rigs in the United States were operating in the Eagle Ford shale region as of September 7, 2012. We expect this heightened Eagle Ford shale activity, as well as activity in the frequently overlying Olmos tight sand formation, will result in higher throughput on our systems and opportunities to expand our asset base over the next several years. Our Mississippi and Alabama assets are strategically positioned to provide transportation of natural gas to our power generation, industrial and utility customers as well as to unaffiliated interstate pipelines. We expect to grow our business and distributable cash flow by expanding the capacity and utilization of our assets and by making selective acquisitions, such as our acquisition of EAI in September 2011.

 

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        Our assets, the majority of which we acquired from Crosstex in August 2009, consist of five gathering systems, three natural gas processing plants, three intrastate pipelines, one fractionator and ancillary assets. The following table provides information regarding our assets by operating region as of June 30, 2012.

Region
  Asset/System Type   Length
(Miles)
  Compression
(Horsepower)
  Throughput
Capacity
(MMcf/d)
  Fractionation
Capacity
(Bbls/d)
 

South Texas

  Gathering pipelines     951     9,736     390        

  Intrastate pipeline     494     1,260     200        

  Processing facilities         47,985     385        

  Fractionation facilities                 4,800  

Mississippi/Alabama

 

Gathering pipelines

   
320
   
26,239
   
415
       

  Intrastate pipeline     825     2,200     305        

Total

 

Gathering pipelines

   
1,271
   
35,975
   
805
       

  Intrastate pipeline     1,319     3,460     505        

  Processing facilities         47,985     385        

  Fractionation facilities                 4,800  

        We generate the majority of our gross operating margin from our business in South Texas. For the six months ended June 30, 2012, we generated $226.3 million of revenue and $40.1 million of gross operating margin. In that time period, 76.8% of our gross operating margin was generated from fixed-fee and fixed-spread arrangements with respect to which we have little or no direct commodity price exposure. For the year ended December 31, 2011, we generated $523.1 million of revenue and $62.6 million of gross operating margin. In that time period, 75.0% of our gross operating margin was generated from fixed-fee and fixed-spread arrangements with respect to which we have little or no direct commodity price exposure. For a definition of gross operating margin and a reconciliation of gross operating margin to its most directly comparable financial measure calculated in accordance with GAAP, please read "Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures."


Our Growth Drivers

        We seek to pursue economically attractive organic expansion and third-party acquisition opportunities that leverage our existing assets and enhance strategic relationships with our customers. We currently expect that opportunities in the Eagle Ford shale area will be a primary driver of our near-term growth due to the increased drilling activity and production of natural gas and NGLs in this area. From January 1, 2011 through September 30, 2012, we commenced or expect to have completed the major acquisitions and growth projects listed below involving estimated capital expenditures of $249.1 million, out of our total expansion capital expenditures of $278.4 million during the same period. Please read "Our Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2013" for more information regarding our forecast of the estimated cash available for distribution we may realize from the projects set forth below.

    we completed construction and commenced operations in July 2012 of a 200 MMcf/d cryogenic processing plant in Refugio County, Texas, which we refer to as our Woodsboro processing plant, to expand our South Texas processing capacity;

    we are expanding our NGL capacity by installing an 11,500 Bbl/d fractionation facility, which we refer to as our Bonnie View fractionation plant, and have constructed associated pipelines in South Texas to transport fractionated NGLs to market;

 

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    we reactivated an idle train at our Gregory processing plant in South Texas, upgraded existing equipment and added new equipment to increase the plant's processing capacity from 85 MMcf/d to 135 MMcf/d while improving recoveries of NGLs from the plant;

    we acquired lateral pipelines near our Gregory processing plant in South Texas that enhance the delivery capacity of our Gregory system and serve as additional gas residue pipelines for our processing plants;

    we acquired EAI, an intrastate natural gas pipeline system and gathering system in northwest and central Alabama that averaged approximately 100 MMcf/d of throughput volume during the first six months of 2012;

    we constructed a 22-mile liquids-rich natural gas extension on our South Texas system (the McMullen pipeline extension) to connect acreage in the Eagle Ford shale liquids-rich natural gas area;

    we constructed a nine-mile pipeline in Jones County, Mississippi that provides us with additional capacity to supply South Mississippi Electric Power Association, or SMEPA;

    we are enhancing efficiency of recovery of NGLs at our Woodsboro processing plant; and

    we are constructing 57 miles of new pipeline to bring additional supply from DeWitt and Karnes Counties in the Eagle Ford shale area to our Woodsboro processing plant.

        Our forecast for the twelve months ending September 30, 2013 also includes the capital expenditures and benefits of the following projects:

    increasing the capacity of our Bonnie View fractionation plant by 11,000 Bbl/d to 22,500 Bbl/d;

    constructing a lateral pipeline in Karnes County to connect additional supplies of liquids-rich gas for delivery to our Woodsboro processing plant;

    constructing new facilities to increase our capacity to produce and market NGLs and transport purity NGL products for our customers (we do not expect to receive any benefits associated with these facilities during our forecast period because of their anticipated completion dates); and

    beginning construction of a second processing plant at Woodsboro along with additional pipelines to provide incremental gas supply (we do not expect to receive any benefits associated with this facility during our forecast period because of its anticipated completion date).

        Please read "Our Cash Distribution Policy and Restrictions on Distributions—Assumptions and Considerations—Capital Expenditures" for more information regarding our anticipated capital expenditures for the twelve months ending September 30, 2013. At the closing of this offering, we expect to have availability under our new credit facility to fund the expenditures contemplated by our capital expenditures budget during our forecast period.


Business Strategies

        Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time by expanding the capacity and efficiency of our assets and by making selective acquisitions while ensuring the ongoing stability of our business. We expect to achieve this objective by pursuing the following business strategies:

    Capitalize on organic growth opportunities, with a focus on high-growth areas such as the Eagle Ford shale.  We intend to continue to evaluate and execute midstream projects that enhance our existing systems as well as our ability to aggregate supply and obtain access to premium markets for that supply. A primary focus of our organic growth will be our South Texas assets located in

 

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      and near the Eagle Ford shale area, a rapidly growing source of unconventional U.S. natural gas production that often features high condensate and NGL content.

    Continue to enhance the profitability of our existing assets.  We intend to increase the profitability of our existing asset base by identifying new business opportunities and adding new volumes of natural gas supplies to our existing assets.

    Pursue accretive acquisitions of complementary assets.  We intend to pursue accretive acquisitions that strategically expand or complement our existing asset portfolio. We monitor the marketplace to identify and pursue such acquisitions, with a particular focus on regions with potential for additional near-term development.

    Manage our exposure to commodity price risk.  Because natural gas and NGL prices are volatile, we will continue to mitigate the impact of fluctuations in commodity prices and to generate more stable cash flows by targeting a contract portfolio that is heavily weighted towards fixed-fee and fixed-spread contracts, which are not directly sensitive to commodity prices, and, where appropriate, hedge a portion of our commodity price exposure.

    Maintain sound financial practices to ensure our long-term viability.  We intend to maintain our commitment to financial discipline, and we generally intend to fund the long-term capital requirements for expansion projects and acquisitions through a prudent combination of equity and debt capital.


Competitive Strengths

        We believe that we are well-positioned to successfully execute our business strategies by capitalizing on the following competitive strengths:

    Strategically located asset base.  The majority of our assets are located in or within close proximity to the Eagle Ford shale area in South Texas, which is one of the most active drilling regions in the United States. In addition, all of our assets have access to major natural gas market areas.

    Reliable cash flows underpinned by long-term, fixed-fee and fixed-spread contracts.  We provide our services primarily under fixed-fee and fixed-spread contracts, which helps to promote cash flow reliability and minimizes our direct exposure to commodity price fluctuations.

    Integrated midstream value chain.  We provide a comprehensive package of services to natural gas producers, including natural gas gathering, processing, treating, compression and transportation and NGL fractionation and transportation. We believe our ability to move producers' natural gas and NGLs from the wellhead to market provides a competitive advantage relative to competing companies that do not offer this range of midstream services.

    Experienced and incentivized management and operating teams.  Our executive officers have an average of 34 years of experience in building, acquiring and managing midstream and other energy assets and are focused on optimizing our existing business and expanding our operations through disciplined development and accretive acquisitions. Most of our field operating managers and supervisors have long-standing experience operating our assets.

    Supportive sponsor with significant industry expertise.  Charlesbank, the principal owner of our general partner, has substantial experience as a private equity investor in the energy and midstream sector. We believe that Charlesbank provides us with strategic guidance, financial expertise and potential capital support that enhances our ability to grow our asset base and cash flow.

 

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Our Sponsor

        Charlesbank is a leading private equity firm with over $2.0 billion of capital under management. The firm has more than 20 investment professionals and offices in Boston and New York. Originally managing an investment portfolio solely for Harvard University, Charlesbank spun-off from Harvard University in 1998, broadening its investor base in 2000 to include other institutional clients. Since 1998, Charlesbank has invested over $2.3 billion in 40 companies across a wide range of industries. In 2003, Charlesbank and members of our management team co-founded Regency Gas Services, a midstream company formed through the acquisition of assets from a publicly traded energy company. Over the years, Charlesbank has obtained deep experience in the energy sector and proven its ability to support and finance a variety of growth projects.


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 18.

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.

    Because of the natural decline in production from existing wells in our areas of operation, our success depends in part on producers replacing declining production and also on our ability to obtain new sources of natural gas. Any decrease in the volumes of natural gas that we gather, compress, process, treat or transport or in the volumes of NGLs that we fractionate or transport could adversely affect our business and operating results.

    Natural gas and NGL prices are volatile, and a change in these prices in absolute terms, or an adverse change in the prices of natural gas and NGLs relative to one another, could adversely affect our gross operating margin and cash flow and our ability to make cash distributions to our unitholders.

    Our exposure to direct commodity price risk may vary over time.

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

    We depend on a relatively limited number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, any one or more of these customers could adversely affect our ability to make cash distributions to you.

    Downtime associated with our assets or third-party assets interconnected with our assets could have a material adverse effect on our business and operating results.

    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

 

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      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.

    We are subject to numerous hazards and operational risks.

Risks Inherent in an Investment in Us

    Holdings 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. Holdings 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.

    Charlesbank is not limited in its ability to compete with us and is 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.

    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.

    Our partnership agreement restricts the rights of holders of our common and subordinated 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.

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.

    You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

 

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Recapitalization Transactions and Partnership Structure

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

    Holdings will convey its indirect ownership interest in our operating subsidiaries to Southcross Energy Operating, LLC, which will become our operating subsidiary;

    Holdings will convey an interest in Southcross Energy Operating, LLC to our general partner as a capital contribution;

    Our general partner will convey its interest in Southcross Energy Operating, LLC to us in exchange for (i) a continuation of its 2% general partner interest in us, and (ii) our incentive distribution rights, or IDRs;

    Holdings will convey its remaining interest in Southcross Energy Operating, LLC to us in exchange for (i) 3,213,713 common units, representing a 12.9% limited partner interest in us, (ii) 12,213,713 subordinated units, representing a 49.0% limited partner interest in us, (iii) the assumption of its existing debt by us, (iv) the right to receive $7.5 million sourced from new debt incurred by us and (v) the right to receive $38.5 million in cash, a portion of which will be used to reimburse Holdings for certain capital expenditures it incurred with respect to assets it contributed to us;

    We will issue 9,000,000 common units to the public, representing a 36.1% limited partner interest in us;

    We will grant up to 150,000 phantom units with distribution equivalent rights to employees, including executive officers (please read "Management — Executive Compensation — 2012 Long-Term Incentive Plan");

    We will enter into a new $350.0 million credit facility from which we will borrow $150.0 million; and

    We will use the net proceeds from the offering and borrowings under our new credit facility as set forth under "Use of Proceeds."

 

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Ownership of Southcross Energy Partners, L.P.

        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

    36.1 %

Holdings Units:

       

Common Units

    12.9 %

Subordinated Units

    49.0 %

General Partner Interest

    2.0 %
       

Total

    100.0 %
       

CHART


(1)
After giving effect to this offering, members of our management will beneficially own 10.6% of the Class A Common Units, 1.9% of the Series A Preferred Units, 0.3% of the Redeemable Preferred Units, 2.1% of the Series B Redeemable Preferred Units and 100.0% of the Special Class B Units of Holdings.

(2)
After giving effect to this offering, Charlesbank Equity Fund VI, Limited Partnership and its affiliated investment funds will beneficially own 85.2% of the Class A Common Units, 93.5% of the Series A Preferred Units, 95.1% of the Redeemable Preferred Units, 73.8% of the Series B Redeemable Preferred Units and none of the Series C Redeemable Preferred Units of Holdings.

(3)
After giving effect to this offering, other individual and institutional investors will beneficially own 4.2% of the Class A Common Units, 4.7% of the Series A Preferred Units, 4.6% of the Redeemable Preferred Units, 24.2% of the Series B Redeemable Preferred Units and none of the Series C Redeemable Preferred Units of Holdings.

(4)
Up to 150,000 phantom units will be issued in connection with this offering to employees, including executive officers, pursuant to our long-term incentive plan.

 

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Our Management

        We are managed and operated by the board of directors and executive officers of Southcross Energy Partners GP, LLC, our general partner. Holdings, which is controlled by Charlesbank, 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 three 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 142.

        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. For the twelve months ending September 30, 2013, we estimate that these expenses will be approximately $26.3 million, which includes, among other items, compensation expense for all employees required to manage and operate our business.


Principal Executive Offices and Internet Address

        Our principal executive offices are located at 1700 Pacific Avenue, Suite 2900, Dallas, Texas 75201 and our telephone number is (214) 979-3700. Our website is located at www.southcrossenergy.com 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.

 

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Summary of Conflicts of Interest and Duties

General

        Our general partner has a legal duty to manage us in a manner it subjectively believes is in our best interest. However, the officers and directors of our general partner also have a fiduciary duty to manage the business of our general partner in a manner beneficial to its owners, including Charlesbank. Certain of the directors of our general partner are also officers of Charlesbank. 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 Charlesbank and our general partner, on the other hand. For example, our general partner will be entitled to make determinations that affect the amount of cash distributions we make to the holders of common units, which in turn has an effect on whether our general partner receives incentive cash distributions.

Partnership Agreement Replacement of Fiduciary Duties

        Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties owed by the general partner to limited partners and the partnership. Pursuant to these provisions, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of the general partner and the methods of resolving conflicts of interest. The effect of these provisions is to restrict the remedies available to our common unitholders for 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.

Charlesbank May Compete Against Us

        Our partnership agreement does not prohibit Charlesbank or its affiliates, other than our general partner, from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Charlesbank 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.

        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. For as long as a company is deemed an emerging growth company, it may take advantage of specified reduced reporting and other regulatory requirements that are generally unavailable to other 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 included in an initial public offering registration statement;

    an exemption to provide less than five years of selected financial data in an initial public offering registration statement;

 

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    an exemption from the auditor attestation requirement in the assessment of the emerging growth company's internal controls over financial reporting;

    an exemption from the adoption of new or revised financial accounting standards until they would apply to private companies;

    an 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;

    reduced disclosure about the emerging growth company's executive compensation arrangements pursuant to the rules applicable to smaller reporting companies; and

    no requirement to seek non-binding advisory votes on executive compensation or golden parachute arrangements.

        We may take advantage of these provisions until we are no longer an emerging growth company, which will occur on the earliest of (i) the last day of the fiscal year following the fifth anniversary of this offering, (ii) the last day of the fiscal year in which we have more than $1.0 billion in annual revenues, (iii) the date on which we have more than $700 million in market value of our common units held by non-affiliates or (iv) the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period.

        We have elected to adopt the reduced disclosure requirements described above, except for the following:

    we have elected to provide three years of audited financial statements and related Management's Discussion and Analysis as opposed to 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).

As a result of these elections, the information that we provide in this prospectus may be different from the information 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

  9,000,000 common units.

 

10,350,000 common units if the underwriters exercise in full their option to purchase additional common units.

Units outstanding after this offering

 

12,213,713 common units and 12,213,713 subordinated units, each representing a 49.0% limited partner interest in us. Our general partner will own 498,518 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 $168.7 million, after deducting underwriting discounts and commissions, to:

 

make a cash distribution to Holdings of $38.5 million, a portion of which will be used to reimburse Holdings for certain capital expenditures it incurred with respect to assets contributed to us;

 

repay $125.0 million of debt outstanding under our existing credit facility;

 

pay Citigroup Global Markets Inc. and Wells Fargo Securities, LLC an aggregate structuring fee of $0.7 million; and

 

pay estimated offering expenses of $4.5 million.

 

Holdings may use a portion of the cash distribution it receives from us to redeem all or a portion of Holdings' outstanding redeemable preferred units.

 

Immediately following the repayment of a portion of the outstanding balance under our existing credit facility, we will terminate our existing facility, enter into a new credit facility and borrow approximately $150.0 million under that credit facility. We will use the proceeds from these borrowings to (i) make an ordinary course cash distribution of approximately $7.5 million to Holdings, (ii) repay the remaining balance of $140.0 million outstanding under our existing credit facility and (iii) pay fees and expenses relating to our new credit facility of approximately $2.5 million.

 

If the underwriters exercise their option to purchase additional common units, we will use the net proceeds from that exercise to redeem from Holdings the number of common units issued upon such exercise, at a price per common unit equal to the proceeds per common unit in this offering before expenses but after deducting underwriting discounts, commissions and structuring fees.

 

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Cash distributions

 

We intend to pay a minimum quarterly distribution of $0.40 per unit ($1.60 per unit on an annualized basis) to the extent we have sufficient cash from operations after the 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 December 31, 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 $0.40 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 $0.40; and

 

third, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unit has received a distribution of $0.46.

 

If cash distributions to our unitholders exceed $0.46 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." Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions."

 

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The amount of historical as adjusted available cash generated during the year ended December 31, 2011 or the twelve months ended June 30, 2012 would not have been sufficient to allow us to pay the minimum quarterly distribution on our common and subordinated units as well as the corresponding distribution on our 2.0% general partner interest during those periods. Specifically, the amount of historical as adjusted available cash generated during the year ended December 31, 2011 would have been sufficient to pay only 91.0% of the aggregate minimum quarterly distribution on our common units during that period, and we would not have been able to pay any distributions on our subordinated units during that period. The amount of historical as adjusted available cash generated during the twelve months ended June 30, 2012 would have been sufficient to pay the annualized minimum quarterly distribution of $1.60 per unit on our common units during that period but only 7.8% of the aggregate minimum quarterly distribution on our subordinated units during that period.

 

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 $1.60 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 legally binding obligation to pay quarterly distributions at our minimum quarterly distribution rate or any other rate except as provided in our partnership agreement. There is no guarantee that we will distribute quarterly cash distributions to our unitholders in any quarter. Please read "Our Cash Distribution Policy and Restrictions on Distributions."

Subordinated units

 

Holdings will initially own all of our subordinated units. The principal difference between our common units and our 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.

 

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Conversion of subordinated units

 

The subordination period will end on the first business day after the partnership has earned and paid at least (1) $1.60 (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 December 31, 2015 or (2) $2.40 (150.0% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and the corresponding distribution 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.

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 Holdings. Upon the closing of this offering, Holdings will own an aggregate of 63.2% of our common and subordinated units (or 57.6% of our outstanding common and subordinated units if the underwriters exercise in full their option to purchase additional units). This will give Holdings 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 has 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.

 

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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 period ending December 31, 2015, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20.0% or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.60 per unit, we estimate that your average allocable federal taxable income per year will be no more than $0.32 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."

Directed unit program

 

At our request, the underwriters have reserved up to 5.0% of the common units being offered by this prospectus for sale at the initial public offering price to the directors, officers and employees of our general partner and certain other persons associated with us through a directed unit program. For further information regarding our directed unit program, please read "Underwriting."

Exchange listing

 

We have been approved to list our common units on the New York Stock Exchange, or NYSE, subject to official notice of issuance, under the symbol "SXE."

   

 

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Summary Historical and Pro Forma Financial and Operating Data

        The following table presents, as of the dates and for the periods indicated, our summary historical and pro forma consolidated financial and operating data, as well as the summary historical combined financial and operating data of our Predecessor.

        The summary historical combined financial data for the period from January 1, 2009 to July 31, 2009 is derived from the audited historical combined financial statements of our Predecessor included elsewhere in this prospectus. The summary historical combined balance sheet data as of July 31, 2009 is derived from the unaudited historical combined financial statements of our Predecessor that are not included in this prospectus. The summary historical consolidated balance sheet data presented as of December 31, 2009 of Southcross Energy LLC is derived from the audited historical consolidated financial statements of Southcross Energy LLC that are not included in this prospectus. The summary historical consolidated financial data presented as of December 31, 2010 and December 31, 2011 and for the period from June 2, 2009 (date of inception) to December 31, 2009 and for the years ended December 31, 2010 and December 31, 2011 have been derived from the audited historical consolidated financial statements of Southcross Energy LLC included elsewhere in this prospectus. The summary historical consolidated financial data presented as of June 30, 2012 and for the six months ended June 30, 2011 and June 30, 2012 are derived from our unaudited historical condensed financial statements included elsewhere in this prospectus. We acquired our initial assets from Crosstex effective as of August 1, 2009. During the period from our inception on June 2, 2009 to July 31, 2009, we had no operations, although we incurred certain fees and expenses of approximately $3.0 million associated with our formation and the acquisition of our initial assets from Crosstex, which are reflected in the "Transaction costs" line item of our summary historical consolidated financial data for the period from June 2, 2009 (date of inception) to December 31, 2009.

        The summary pro forma consolidated financial data for the six months ended June 30, 2012 and for the year ended December 31, 2011 have been derived from our unaudited pro forma consolidated financial statements included elsewhere in this prospectus. The summary pro forma consolidated statement of operations for the year ended December 31, 2011 includes the pro forma effects of the EAI acquisition and the pro forma effects of the recapitalization transactions described under "—Recapitalization Transactions and Partnership Structure" as if the EAI acquisition and the recapitalization transactions occurred as of January 1, 2011. The summary pro forma consolidated statement of operations for the six months ended June 30, 2012 presents the pro forma effects of the recapitalization transactions as if they occurred as of January 1, 2011.

        For a detailed discussion of 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 Southcross Energy LLC and our Predecessor's audited combined financial statements and related notes included elsewhere in this prospectus. Among other things, those historical financial

 

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statements include more detailed information regarding the basis of presentation for the information below.

 
  Southcross Energy
Predecessor
   
  Southcross Energy LLC    
  Pro Forma
Southcross
Energy Partners, L.P.
 
 
   
   
 
 
   
  Period from
June 2, 2009 to
December 31,

  Year Ended
December 31,
  Six Months Ended
June 30,
   
 
 
  Period from
January 1, 2009 to

   
   
   
  Six
Months
Ended
June 30, 2012
 
 
   
   
  Year Ended
December 31, 2011
 
 
  July 31, 2009    
  2009   2010   2011(3)   2011   2012    
 
 
  (in thousands, except for volume and price amounts)
   
   
   
 

Statement of Operations Data:

                                                         

Total Revenue

  $ 330,870       $ 206,634   $ 498,747   $ 523,149   $ 247,489   $ 226,319       $ 548,152   $ 226,319  

Expenses:

                                                         

Cost of natural gas and liquids sold

    301,368         179,045     439,431     460,580     217,125     186,204         479,376     186,204  

Operations and maintenance

    10,648         7,847     21,106     24,707     10,293     15,579         28,701     15,579  

Depreciation and amortization

    7,268         4,235     10,987     12,345     5,602     7,338         13,200     7,338  

General and administrative

    9,788         3,225     7,341     8,926     4,227     5,636         9,312     5,636  

Transaction costs

            2,957     149     203                 203      
                                           

Total expenses

    329,072         197,309     479,014     506,761     237,247     214,757         530,792     214,757  
                                           

Income from operations

    1,798         9,325     19,733     16,388     10,242     11,562         17,360     11,562  

Interest income

            9     25     24     15     4         24     4  

Loss on extinguishment of debt

                    (3,240 )   (3,240 )           (3,240 )    

Interest expense

            (4,554 )   (10,038 )   (5,372 )   (2,817 )   (3,135 )       (6,407 )   (1,726 )

Income tax expense

    (77 )       (372 )   (1 )   (261 )   (166 )   (256 )       (261 )   (256 )
                                           

Net income

  $ 1,721       $ 4,408   $ 9,719   $ 7,539   $ 4,034   $ 8,175       $ 7,476   $ 9,584  
                                           

Statement of Cash Flows Data:

                                                         

Net cash provided by (used in):

                                                         

Operating activities

  $ 4,955       $ 10,164   $ 25,493   $ 20,007   $ 10,402   $ 12,244                  

Investing activities

    (791 )       (238,339 )   (5,231 )   (144,602 )   (37,174 )   (71,603 )                

Financing activities

    (4,164 )       233,899     (5,663 )   105,684     47,545     61,241                  

Balance Sheet Data (at period end):

                                                         

Cash and cash equivalents

  $       $ 5,724   $ 20,323   $ 1,412   $ 41,096   $ 3,294                  

Trade accounts receivable

    50,707         39,956     35,059     41,234     33,696     30,462                  

Property, plant, and equipment, net

    111,645         235,065     229,309     369,861     275,120     448,367                  

Total assets

    167,503         287,808     289,643     420,385     353,543     492,469                  

Total debt (current and long term)

            119,949     115,000     208,280     150,125     214,535                  

Other Financial Data:

                                                         

Adjusted EBITDA(1)

  $ 9,236       $ 16,517   $ 30,869   $ 28,936   $ 12,604   $ 19,046       $ 30,763   $ 19,046  

Gross operating margin(2)

    29,502         27,589     59,316     62,569     30,364     40,115         68,776     40,115  

Maintenance capital expenditures

    565         3,025     3,402     5,317     1,728     1,736         5,423     1,736  

Expansion capital expenditures

    250         1,669     1,843     150,669     49,685     84,080         150,669     84,080  

Operating data:

                                                         

Average throughput of gas (MMBtu/d)

    592,243         492,350     471,265     506,975     446,271     576,404         532,746     576,404  

Average volume of NGLs delivered (Mgal/d)

    241.8         225.5     233.4     215.5     207.2     377.8         215.5     377.8  

Average volume input to our processing plants (MMBtu/d)

    100,596         96,135     95,336     97,028     84,462     123,234         97,028     123,234  

Realized prices on natural gas volumes sold/Btu ($/MMBtu)

  $ 3.95       $ 3.97   $ 4.42   $ 4.05   $ 4.27   $ 2.48       $ 4.07   $ 2.48  

Realized prices on NGL volumes sold/gal ($/gal)

  $ 0.69       $ 1.01   $ 1.10   $ 1.35   $ 1.25   $ 0.98       $ 1.35   $ 0.98  

(1)
For a definition of Adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read "Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures," and for a discussion of how we use Adjusted EBITDA to evaluate our operating performance, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations."

(2)
For a definition of gross operating margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read "Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures," and for a discussion of how we use gross operating margin to evaluate our operating performance, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations."

(3)
The Summary Historical Financial and Operating Data for the year ended December 31, 2011 includes four months of financial and operating results for the EAI acquisition.

 

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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 $0.40 per unit per quarter, or $1.60 per unit on an annualized basis, we will require available cash of approximately $10.0 million per quarter, or $40.1 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, process, treat, compress and transport and the volume of NGLs we fractionate and transport;

    the level of production of oil and natural gas and the resultant market prices of oil, natural gas and NGLs;

    damage to pipelines, facilities, plants, related equipment and surrounding properties caused by hurricanes, earthquakes, floods, fires, severe weather, explosions and other natural disasters and acts of terrorism including damage to third party pipelines or facilities upon which we rely for transportation services;

    outages at the processing or fractionation facilities owned by us or third parties caused by mechanical failure and maintenance, construction and other similar activities;

    leaks or accidental releases of products or other materials into the environment, whether as a result of human error or otherwise;

    prevailing economic and market conditions;

    realized pricing impacts on our revenue and expenses that are directly subject to commodity price exposure;

    the market prices of natural gas and NGLs relative to one another, which affects our processing margins;

    capacity charges and volumetric fees associated with our transportation services;

    the level of competition from other midstream energy companies in our geographic markets;

    the level of our operating, maintenance and general and administrative costs; and

    regulatory action affecting the supply of, or demand for, natural gas, the maximum transportation rates we can charge on our pipelines, our existing contracts, our operating costs or our operating flexibility.

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        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 of capital expenditures we make;

    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.

        The amount of historical as adjusted cash available for distribution generated during the year ended December 31, 2011 was $18.0 million, which would have allowed us to pay only 91.0% of the aggregate minimum quarterly distribution on all of our common units during that period, and we would not have been able to pay any distributions on our subordinated units during that period. The amount of historical as adjusted cash available for distribution generated during the twelve months ended June 30, 2012 was $21.3 million, which would have allowed us to pay the annualized minimum quarterly distribution of $1.60 per unit on our common units during that period but only 7.8% of the aggregate minimum quarterly distribution on all of our subordinated units during 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." If we are not able to generate additional cash for distribution to our unitholders in future periods, 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.

    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. 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, processed, transported and sold 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.

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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 producers replacing declining production and also on our ability to obtain new sources of natural gas. Any decrease in the volumes of natural gas that we gather, compress, process, treat or transport or in the volumes of NGLs that we fractionate or transport could 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, 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, (ii) our ability to compete for volumes from successful new wells and (iii) our ability to compete successfully for volumes from sources connected to other pipelines.

        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 or production decisions, which are affected by, among other things:

    the availability and cost of capital;

    prevailing and projected oil, natural gas and NGL prices;

    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 oil and natural gas reserves. Drilling and production activity generally decreases as natural gas prices decrease. Further declines in natural gas prices could have a negative impact on exploration, development and production activity, and if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation could lead to reduced utilization of our assets.

        Because of these and other factors, even if 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.

    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 intend to obtain independent evaluations of natural gas reserves connected to our systems on a regular or ongoing basis. Accordingly, we may not have independent 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.

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    Our success depends on drilling activity and our ability to attract and maintain customers in a limited number of geographic areas.

        A significant portion of our assets is located in the Eagle Ford shale area, and we intend to focus our future capital expenditures largely on developing our business in this area. As a result, our financial condition, results of operations and cash flows are significantly dependent upon the demand for our services in this area. Due to our focus on this area, an adverse development in natural gas production from this area would have a significantly greater impact on our financial condition and results of operations than if we spread expenditures more evenly over a wider geographic area. For example, a change in the rules and regulations governing operations in or around the Eagle Ford shale area could cause producers to reduce or cease drilling or to permanently or temporarily shut-in their production within the area, which could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

    Natural gas and NGL prices are volatile, and a change in these prices in absolute terms, or an adverse change in the prices of natural gas and NGLs relative to one another, could adversely affect our gross operating margin and cash flow and our ability to make cash distributions to our unitholders.

        We are subject to risks due to frequent and often substantial fluctuations in commodity prices. In the past, the prices of natural gas, NGLs and other commodities have been extremely volatile, and we expect this volatility to continue. Our future cash flow may be materially adversely affected if we experience significant, prolonged pricing deterioration. For example, if there is a significant change in the relative prices of NGLs and natural gas, it will impact our processing margins, which are a significant component of our ability to generate cash for distribution to our unitholders.

        The markets for and prices of natural gas, NGLs and other commodities depend on factors that are beyond our control. These factors include the supply of and demand for these commodities, which fluctuate with changes in market and economic conditions and other factors, including:

    worldwide economic conditions;

    worldwide political events, including actions taken by foreign oil and natural gas producing nations;

    worldwide weather events and conditions, including natural disasters and seasonal changes;

    the levels of domestic production and consumer demand;

    the availability of transportation systems with adequate capacity;

    the volatility and uncertainty of regional pricing differentials;

    the price and availability of alternative fuels;

    the effect of energy conservation measures;

    the nature and extent of governmental regulation and taxation;

    fluctuations in demand from electric power generators and industrial customers; and

    the anticipated future prices of oil, natural gas, NGLs and other commodities.

    Our exposure to direct commodity price risk may vary over time.

        We currently generate a majority of our revenues pursuant to fixed-fee and fixed spread contracts under which we are paid based on the volumes of natural gas that we gather, process, treat, compress and transport and the volumes of NGLs we fractionate and transport, rather than the value of the underlying natural gas or NGLs. Consequently, the majority of our existing operations and cash flows have limited direct exposure to commodity price risk. Although we intend to enter into similar fixed-fee contracts with new customers in the future, our efforts to obtain such contractual terms may not be

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successful. In addition, we may acquire or develop additional midstream assets or change the arrangements under which we process our volumes, in either case, in a manner that increases our exposure to commodity price risk. 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.

    Unexpected volume changes due to production variability or to gathering, plant or pipeline system disruptions may increase our exposure to commodity price movements.

        We sell processed natural gas to third parties at plant tailgates, pipeline pooling points or at inlet meters to the sites of industrial and utility customers. These sales may be interrupted by disruptions to volumes anywhere along the system. We attempt to balance sales with volumes supplied, but unexpected volume variations due to production variability or to gathering, plant or pipeline system disruptions may expose us to volume imbalances which, in conjunction with movements in commodity prices, could materially impact our income from operations and cash flow.

    We may not successfully balance our purchases and sales of natural gas, which would increase our exposure to commodity price risks.

        We purchase from producers and other suppliers a substantial amount of the natural gas that flows through our pipelines and processing facilities for sale to third parties, including natural gas marketers and other purchasers. We are exposed to fluctuations in the price of natural gas through volumes sold pursuant to percent-of-proceeds arrangements and, to a lesser extent, through volumes sold pursuant to our fixed-spread contracts.

        In order to mitigate our direct commodity price exposure, we typically do not enter into natural gas hedge contracts, but rather attempt to balance our natural gas sales with our natural gas purchases on an aggregate basis across all of our systems. We may not be successful in balancing our purchases and sales, and as such may become exposed to fluctuations in the price of natural gas. For example, we are currently net purchasers of natural gas on certain of our systems and net sellers of natural gas on certain of our other systems. Our overall net position with respect to natural gas can change over time and our exposure to fluctuations in natural gas prices could materially increase, which in turn could result in increased volatility in our revenue, gross operating margin and cash flows.

        Although we enter into back-to-back purchases and sales of natural gas in our fixed-spread contracts in which we purchase natural gas from producers or suppliers at receipt points on our systems and simultaneously sell an identical volume of natural gas at delivery points on our systems, we may not be able to mitigate all exposure to commodity price risks. For example, the volumes or timing of our purchases and sales may not correspond. In addition, a producer or supplier could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause our purchases and sales to become unbalanced. If our purchases and sales are unbalanced, we will face increased exposure to commodity price risks, which in turn could result in increased volatility in our revenue, gross operating margin and cash flows.

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

        We compete with other similarly sized midstream companies in our areas of operation. Some of our competitors are large companies that have greater financial, managerial and other resources than we do. In addition, some of our competitors have assets in closer proximity to natural gas supplies and have available idle capacity in existing assets that would not require new capital investments for use. Our competitors may expand or construct gathering, compression, treating, processing or transportation systems or NGLs fractionation facilities that would create additional competition for the services we provide to our customers. In addition, our customers may develop their own gathering, compression, treating, processing or transportation systems or NGLs fractionation facilities in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current

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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.

    Our gathering, processing and transportation contracts subject us to renewal risks.

        We gather, purchase, process, treat, compress, transport and sell most of the natural gas and NGLs 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. For example, depending on prevailing market conditions at the time of a contract renewal, gathering and processing customers with fixed-fee or fixed-spread contracts may desire to enter into gathering and transportation contracts under different fee arrangements, or a producer with whom we have a natural gas purchase contract may choose to enter into a transportation contract with us and retain title to its natural gas. 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 revenue, gross operating margin and cash flows could decline and our ability to make cash distributions to our unitholders could be materially and adversely affected.

    We depend on a relatively limited number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, any one or more of these customers could adversely affect our ability to make cash distributions to you.

        A significant percentage of our revenue is attributable to a relatively limited number of customers. Our top ten customers accounted for approximately 73.1% and 70.4% of our revenue for the year ended December 31, 2011 and for the six months ended June 30, 2012, respectively. We have gathering, processing and/or transmission contracts with each of these customers of varying duration and commercial terms. If we were unable to renew our contracts with one or more of these customers on favorable terms, we may not be able to replace any of these customers in a timely fashion, on favorable terms or at all. Two customers, Formosa Hydrocarbons Company, Inc., or Formosa, and Sherwin Alumina Company accounted for approximately 20.8% and 15.5%, respectively, of our revenue for the year ended December 31, 2011. We supply natural gas to Sherwin Alumina Company to be used in their manufacturing process. In the case of Formosa, we have a contract to sell to Formosa natural gas that is supplied to us by our producers for processing at its facility. We then share in the value stream created by Formosa's processing plant. The contract that enables us to use Formosa's processing facility will expire in January 2013. We expect that we will have the ability to take the same natural gas volume from our producers and process it at our own facilities, in particular at our new Woodsboro processing facility. If Formosa denies us access to its processing facility prior to January 2013, it may have a material adverse effect on our revenue, cash flows and our ability to make cash distributions to our unitholders. In addition, 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, gross operating margin 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 limited number of customers for a substantial portion of our revenue.

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

        Our natural gas gathering and transportation pipelines, NGL pipelines and processing facilities connect to other pipelines or facilities owned and operated by unaffiliated third parties, such as Tennessee Gas Pipeline Company, Florida Gas Transmission Company, LLC, Gulf South Pipeline Company, LP, Kinder Morgan Energy Partners LP, Southern Natural Gas Company, Energy Transfer Partners, L.P., Seadrift Pipeline Corporation and others. The continuing operation of such third-party pipelines, processing plants and other midstream facilities is not within our control. These pipelines, plants 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 hurricanes or other operational hazards. In addition, if the costs to us to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurred, if any of these pipelines or other midstream facilities become unable to receive, transport or process natural gas, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our gross margin and ability to make cash distributions to our unitholders could be adversely affected. For example, for 31 days in September and October 2011 and for 34 days in August and September 2012, Formosa shut down its processing plant in order to expand or conduct turnaround maintenance on its facilities, thereby causing us to curtail natural gas supply while shutting in our deliveries to Formosa's processing plant.

    Significant portions of our pipeline systems and processing plants have been in service for several decades and 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 and processing and treating plants that could have a material adverse effect on our business and operating results.

        We purchased the majority of our assets from Crosstex in August 2009. Significant portions of the pipeline systems and processing plants that we purchased have been in service for many decades. Our executive management team was hired shortly before that purchase and, consequently, has a limited history of operating our assets. There may be historical occurrences or latent issues regarding our pipeline systems that our executive management team may be unaware of and that may have a material adverse effect on our business and results of operations. The age and condition of our pipeline systems could also result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of our pipeline systems could adversely affect our business and results of operations and our ability to make cash distributions to our unitholders.

    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, treating, processing and transportation of natural gas and the fractionation and transportation of NGLs, including:

    damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters, acts of terrorism and actions by third parties;

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    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.

For example

    During the month of September 2008, before we acquired it, the Gregory processing plant temporarily shut down after Hurricane Ike made landfall because there was no outlet for its produced NGL product;

    In May 2011, flooding associated with high water on the Mississippi River caused a force majeure event that shut down deliveries through and revenue on our Delta pipeline for 20 days;

    In June and July 2011, the molecular sieve support screen failed in the Gregory processing plant dehydrator vessel. We shut down the plant for approximately one month to make necessary repairs; and

    In June and July 2012, the regenerator heater failed at the Gregory processing plant. We reduced NGL recoveries at the plant for approximately 21 days to make the necessary repairs.

        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. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. For example our business interruption/loss of income insurance provides limited coverage in the event of damage to any of our underground facilities. In addition, although we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. 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, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential environmental liabilities.

    We intend to grow our business in part by seeking strategic acquisition opportunities. If we are unable to make acquisitions on economically acceptable terms from 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 is affected, 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 or (iii) outbid by

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competitors or for any other reason, then our future growth and ability to increase cash distributions could be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.

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

    mistaken assumptions about volumes, revenue and costs, including synergies;

    an inability to secure adequate customer commitments to use the acquired systems or facilities;

    the risk that natural gas 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, particularly given the relatively small size of our management team and its limited history with our assets;

    coordinating geographically disparate organizations, systems and facilities;

    the assumption of unknown liabilities;

    limitations on rights to indemnity from the seller;

    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 growth strategy requires access to new capital. Tightened capital markets or increased competition for investment opportunities could impair our ability to grow.

        We continuously consider and enter into discussions regarding potential acquisitions or growth capital expenditures. Any limitations on our access to new capital will impair our ability to execute this strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire strategic and accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our initial cost of equity include market conditions, including our then current unit price, fees we pay to underwriters and other offering costs, which include amounts we pay for legal and accounting services. The primary factors influencing our cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges we pay to lenders.

        Weak economic conditions and the volatility and disruption in the financial markets could increase the cost of raising money in the debt and equity capital markets substantially while diminishing the availability of funds from those markets. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers. These factors may impair our ability to execute our growth strategy.

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        In addition, we are experiencing increased competition for the types of assets we contemplate purchasing. Weak economic conditions and competition for asset purchases could limit our ability to fully execute our growth strategy.

    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 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 our 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.

        As of September 30, 2012, we had total indebtedness of $253.2 million. 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.

    A shortage of skilled labor in the midstream natural gas industry could reduce labor productivity and increase costs, which could have a material adverse effect on our business and results of operations.

        The gathering, treating, processing and transporting of natural gas and the fractionation of NGLs 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.

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    Restrictions in our new credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.

        We intend to enter into a new credit facility in connection with the closing of this offering. Our new credit facility is likely to limit our ability to, among other things:

    incur or guarantee additional debt;

    make distributions on or redeem or repurchase units;

    make certain investments and acquisitions;

    make capital expenditures;

    incur certain liens or permit them to exist;

    enter into certain types of transactions with affiliates;

    merge or consolidate with another company; and

    transfer, sell or otherwise dispose of assets.

        Our new credit facility also will likely contain covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests.

        The provisions of our new 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 new 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.

    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. 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. Congress continues to consider legislation to amend the Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under that Act's Underground Injection Control Program and to require disclosure of chemicals used in the hydraulic fracturing process. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a multi-year study of the potential environmental impacts of hydraulic fracturing, the results of which are anticipated to be available in 2012. In addition, on October 20, 2011, the EPA announced its intention to propose regulations by 2014 under the federal Clean Water Act to develop standards for wastewater discharges from hydraulic fracturing and other natural gas production activities.

        Several states have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. For example, on December 13, 2011 the Texas Railroad Commission adopted the Hydraulic Fracturing Chemical Disclosure Rule implementing a state law passed in June 2011, requiring public disclosure of hydraulic fracturing fluid contents for wells drilled under drilling permits issued after

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February 1, 2012. We cannot predict whether any other legislation will be enacted and if so, what its provisions would be. If additional levels of regulation and permits are 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.

        On April 17, 2012, the EPA approved final rules that establish new air emission controls for oil and natural gas production and natural gas processing operations. This new rule addresses emissions of various pollutants frequently associated with oil and natural gas production and processing activities. The rule also establishes specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, gas processing plants and certain other equipment. This rule may require a number of modifications to our and our customers' operations, including the installation of new equipment to control emissions. Compliance with such rules could result in additional costs, including increased capital expenditures and operating costs, for us and our customers, which may adversely impact our cash flows and results of operations.

    Our pipelines 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, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. The Pipeline and Hazardous Materials Safety Administration of the DOT 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 add new regulations governing the safety of gathering lines. Such legislative and regulatory changes could have a material effect on our operations and costs of transportation service due to more stringent and comprehensive safety regulation and higher penalties for violations of those regulations.

    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, if we expand a pipeline, the construction may occur over an extended period of time, yet we will not receive any material increases in revenue until the project is completed and placed into service. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize or only materializes over a period materially longer than expected. Since we are not engaged in the exploration for and development of natural gas and oil reserves, we often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in that area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate as a result of the numerous uncertainties inherent in estimating quantities of future production. As a result, new

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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 and transportation assets may require us to obtain new rights-of-way or environmental authorizations. We may be unable to obtain such rights-of-way or 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.

    A change in the jurisdictional characterization or regulation of our assets by federal, state or local regulatory agencies or a change in policy by those agencies could result in increased regulation of our assets which could materially and adversely affect our financial condition, results of operations and cash flows.

        Intrastate transportation facilities that do not provide interstate transmission services and gathering facilities (whether or not they provide interstate transportation services) are exempt from the jurisdiction of the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or NGA. Although the FERC has not made any formal determinations with respect to any of our facilities, we believe that our intrastate natural gas pipelines and related facilities that are not engaged in providing interstate transmission services are engaged in exempt gathering and intrastate transportation and, therefore, are not subject to FERC jurisdiction. We also believe that our natural gas gathering pipelines meet the traditional tests that the FERC has used to determine if a pipeline is a gathering pipeline and is therefore not subject to the FERC's jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation and, over time, the FERC's policy for determining which facilities it regulates has changed. In addition, the distinction between FERC-regulated transmission facilities, on the one hand, and intrastate transportation and gathering facilities, on the other, is a fact-based determination made by the FERC on a case-by-case basis. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or the Natural Gas Policy Act of 1978, or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.

        Some of our intrastate pipelines provide interstate transportation service regulated under Section 311 of the Natural Gas Policy Act of 1978, or NGPA. Rates charged under NGPA Section 311 are limited to rates deemed by FERC to be "fair and equitable." Accordingly, such regulation may prevent us from recovering our full cost of service allocable to such interstate transportation service. In addition, some of our intrastate pipelines may be subject to complaint-based state regulation with respect to our rates and terms and conditions of service, which may prevent us from recovering some of our costs of providing service. The inability to recover our full costs due to FERC and state regulatory oversight and compliance could materially and adversely affect our revenues.

        Moreover, FERC regulation affects our gathering, transportation and compression business generally. The FERC's policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, market transparency, market manipulation, ratemaking, capacity release, segmentation and market center promotion, directly and indirectly affect our gathering business. In addition, the classification and regulation of our gathering

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and intrastate transportation facilities also are subject to change based on future determinations by the FERC, the courts or Congress.

        State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, the FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies, which has resulted in a number of these companies transferring gathering facilities to federally unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels.

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

        Our natural gas gathering, compression, treating and transportation operations and NGLs fractionation services are subject to stringent and complex federal, state and local environmental laws and regulations that govern the discharge of materials into the environment or otherwise relate to environmental protection. Examples of these laws include:

    the federal Clean Air Act and analogous state laws that impose obligations related to air emissions;

    the federal Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or the Superfund law, and analogous state laws that regulate the cleanup of hazardous substances that may be or have been released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal;

    the federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws that regulate discharges from our facilities into state and federal waters, including wetlands;

    the federal Oil Pollution Act, also known as OPA, and analogous state laws that establish strict liability for releases of oil into waters of the United States;

    the federal Resource Conservation and Recovery Act, also known as RCRA, and analogous state laws that impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities;

    the Endangered Species Act, also known as the ESA; and

    the Toxic Substances Control Act, also known as TSCA, and analogous state laws that impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.

        These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations or at locations currently or previously owned or operated by us. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions or costly pollution control measures. Failure to comply with these laws, regulations and permits may result in the assessment of 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

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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 hydrocarbon 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 or transportation 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 integrity management program testing and related repairs.

        Pursuant to the Pipeline Safety Improvement Act of 2002, as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, the DOT, through its Pipeline and Hazardous Materials Safety Administration, has adopted regulations requiring pipeline operators to develop integrity management programs for transmission pipelines located where a leak or rupture could harm "high consequence areas" unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. High consequence areas include high population areas, areas that are sources of drinking water, ecological resource areas that are unusually sensitive to environmental damage from a pipeline release and commercially navigable waterways. 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.

        Moreover, the recently enacted Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 could result in the adoption of additional regulatory requirements that will apply to us. In addition, many states, including the states in which we operate, have adopted regulations similar to existing DOT regulations for intrastate pipelines. Although many of our natural gas facilities fall within a class that is currently not subject to these requirements, we may incur significant costs and liabilities associated with repair, remediation, preventative or mitigation measures associated with our non-exempt pipelines, particularly our Gregory and Gulf Coast Systems. We currently estimate that we will incur costs of approximately $2.0 million during 2012 to complete the testing required by existing

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DOT regulations and their state counterparts. This estimate does not include the costs for any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial. Such costs and liabilities might relate to repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down our pipelines during the pendency of such repairs. Additionally, should we fail to comply with DOT or comparable state regulations, we could be subject to penalties and fines. If future DOT pipeline integrity management regulations were to require that we expand our integrity management program to currently unregulated pipelines, including gathering lines, costs associated with compliance may have a material effect on 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. 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 smaller sources such as our gas-fired compressors could become subject to GHG-related regulation. Depending on the particular program, we could be required to control emissions or to purchase and surrender allowances for GHG emissions resulting from our operations.

        Independent of Congress, the EPA is beginning to adopt regulations controlling GHG emissions under its existing Clean Air Act authority. For example, on December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In 2009, the EPA adopted rules regarding regulation of GHG emissions from motor vehicles. In addition, on September 22, 2009, the EPA issued a final rule requiring the monitoring and reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. Our Gregory and Conroe processing facilities are currently required to report under this rule beginning in 2011. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule for petroleum and natural gas facilities, including natural gas transmission compression facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year. The rule, which went into effect on December 30, 2010, requires reporting of greenhouse gas emissions by regulated facilities to the EPA by September 2012 for emissions during 2011 and annually thereafter. Currently, it is anticipated that several of our facilities will likely be required to report under this rule. However, operational or regulatory changes could require some or all of our other facilities to be required to report GHG emissions at a future date. In 2010, EPA also issued a final rule, known as the "Tailoring Rule," that makes certain large stationary sources and

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modification projects subject to permitting requirements for greenhouse gas emissions under the Clean Air Act. Several of the EPA's greenhouse gas rules are being challenged in pending court proceedings and, depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA could develop new rules.

        Although it is not possible at this time to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business, any future federal or state laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the natural gas we gather, treat or otherwise handle in connection with our services. The potential increase in the costs of our operations resulting from any legislation or regulation to restrict emissions of greenhouse gases could include new or increased costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. While we may be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities, such recovery of costs is uncertain. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for natural gas, resulting in a decrease in demand for our services. We cannot predict with any certainty at this time how these possibilities may affect our operations.

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

        In July 2010 federal legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, was enacted. 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 Commodity Futures Trading Commission, or 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.

        The impact of the Dodd-Frank Act on our hedging activities is uncertain at this time, and the CFTC has not yet promulgated final regulations implementing the key provisions. Although we do not believe we will need to register as a swap dealer or major swap participant, and do not believe we will be subject to the new requirements to trade on an exchange or swap execution facility or to clear swaps through a central counterparty, we may have new regulatory burdens. Moreover, the changes to the swap market as a result of Dodd-Frank implementation could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reduce the availability of new or existing swaps.

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

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the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

    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. 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.

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

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

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

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    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

    Holdings 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. Holdings 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.

        Following this offering, Holdings will control our general partner, and appoint all of the officers and directors of our general partner, some of whom will also be officers of Charlesbank, the entity that controls Holdings. Although our general partner has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is beneficial to its ultimate owner, Holdings. Conflicts of interest may arise between Holdings 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 Holdings 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 Holdings to pursue a business strategy that favors us.

    Our general partner is allowed to take into account the interests of parties other than us, such as Holdings, 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, limits our general partner's liabilities, and also restricts 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, issuances of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

    Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert to common units.

    Our general partner determines which costs incurred by it are reimbursable by us.

    Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.

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    Our partnership agreement permits us to classify up to $35.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights.

    Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

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

    Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.

    Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.

    Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

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

        Please read "Conflicts of Interest and Duties."

    Charlesbank is not limited in its ability to compete with us and is 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.

        Charlesbank is not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. For example, Charlesbank owns an interest in the general partner of a publicly traded midstream master limited partnership, which, in the future, may engage in the natural gas gathering and processing segment of the midstream industry and conduct business in our areas of operation. In addition, in the future, Charlesbank 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 Charlesbank may offer us the opportunity to buy additional assets from it, it is under no contractual obligation to do so and we are unable to predict whether or when such acquisitions might be completed. Charlesbank is a leading private equity firm with significantly greater resources than us and has experience making investments in midstream energy businesses. Charlesbank may compete with us for investment opportunities and may own interests in entities that compete with us.

        Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors, and Charlesbank. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential

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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 3,213,713 common and 12,213,713 subordinated units, representing an aggregate 61.9% limited partner interest in us. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

        The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

    our quarterly distributions;

    our quarterly or annual earnings or those of other companies in our industry;

    the loss of a large customer;

    announcements by us or our competitors of significant contracts or acquisitions;

    changes in accounting standards, policies, guidance, interpretations or principles;

    general economic conditions;

    the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;

    future sales of our common units; and

    other factors described in these "Risk Factors."

    Our 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.

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    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, and we do not anticipate there being limitations in our new 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 26.3% of the outstanding common units and all of our outstanding subordinated units. Please read "The Partnership Agreement—Amendment of Our Partnership Agreement."

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

        Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including Holdings, 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, which we project to be approximately $26.3 million for the twelve months ending September 30, 2013 and includes, among other items, compensation expense for all employees required to manage and operate our business. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our common unitholders. Please read "Our Cash Distribution Policy and Restrictions on Distributions."

    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 the fiduciary duties to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with

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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, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This entitles our general partner to consider only the interests and 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 elect to reset target distribution levels;

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

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

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

    Our partnership agreement restricts the rights of holders of our common and subordinated units with respect to actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

        Our partnership agreement contains provisions that restrict the rights of 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 it subjectively believed that the decision was in the best interest of the partnership and our unitholders, and except as specifically provided by our partnership agreement, 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

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

        Our 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 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 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, 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.

        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

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distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then-current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels related to our general partner's incentive distribution rights. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner's Right to Reset Incentive Distribution Levels."

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

        Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner will be chosen by Holdings. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

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

        The unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates 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 63.2% 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 the conversion of all subordinated units to common units.

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

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

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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 Holdings to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers. This effectively permits a "change of control" without the vote or consent of the unitholders.

    You will experience immediate and substantial dilution in net tangible book value of $6.76 per common unit.

        The estimated initial public offering price of $20.00 per common unit exceeds our net tangible book value of $13.24 per unit. Based on the estimated initial public offering price of $20.00 per common unit, you will incur immediate and substantial dilution in net tangible book value of $6.76 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 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;

    the ratio of taxable income to distributions may increase;

    the relative voting strength of each previously outstanding unit may be diminished; and

    the market price of the common units may decline.

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

        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, Holdings will hold an aggregate of 3,213,713 common units and 12,213,713 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. 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 the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the

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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, Holdings will own approximately 26.3% of our 12,213,713 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), Holdings will own approximately 63.2% of our outstanding common units. For additional information about this right, please read "The Partnership Agreement—Limited Call Right."

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

        A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:

    we were conducting business in a state but had not complied with that particular state's partnership statute; or

    your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute "control" of our business.

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

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

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

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

        We have been approved to list our common units on the NYSE, subject to official notice of issuance. Because we will be a publicly traded partnership, the NYSE does not require us 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

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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, Sarbanes-Oxley 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 $2.2 million of estimated incremental annual 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.

    If we are deemed to be an "investment company" under the Investment Company Act of 1940, it would adversely affect the price of our common units and could have a material adverse effect on our business.

        Our initial assets will consist of our ownership interests in our operating subsidiaries. If a sufficient amount of our other assets are deemed to be "investment securities," within the meaning of the Investment Company Act of 1940, or the Investment Company Act, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or contract rights so as to fall outside of the definition of investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property from or to our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events would adversely affect the price of our common units and could have a material adverse effect on our business.

        Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes, in which case we would be treated as a corporation for federal income tax purposes. As a result, we would pay federal income tax on our taxable income at the corporate tax rate, distributions to you would generally be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to you. If we were taxed as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as an investment company would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units. For a discussion of the federal income tax implications that would result from our treatment as a corporation in any taxable year, please read "Material Federal Income Tax Consequences—Partnership Status."

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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. Members of the U.S. Congress have considered substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships; any such legislation, if enacted, may or may not be applied retroactively. We are unable to predict whether any such legislation will ultimately be enacted, and 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 it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

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

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

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

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

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

        Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them.

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Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.

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

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

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

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

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

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

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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 could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Constructive Termination" for a discussion of the consequences of our termination for federal income tax purposes.

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    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 they 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, Mississippi and Alabama. Some of these states currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is 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 $168.7 million, after deducting underwriting discounts and commissions, from the issuance and sale of common units offered by this prospectus. Our estimates assume an initial public offering price of $20.00 per common unit. We will use the net proceeds from this offering to:

    make a cash distribution to Holdings of $38.5 million, a portion of which will be used to reimburse Holdings for certain capital expenditures it incurred with respect to assets contributed to us;

    repay $125.0 million of debt outstanding under our existing credit facility;

    pay Citigroup Global Markets Inc. and Wells Fargo Securities, LLC an aggregate structuring fee of $0.7 million; and

    pay estimated offering expenses of $4.5 million.

        Holdings may use a portion of the cash distribution it receives from us to redeem all or a portion of Holdings' outstanding redeemable preferred units.

        Immediately following the repayment of a portion of the outstanding balance under our existing credit facility with the net proceeds of this offering, we will terminate our existing credit facility, enter into a new credit facility and borrow approximately $150.0 million under that credit facility. We will use the proceeds from these borrowings to (i) make an ordinary course cash distribution of approximately $7.5 million to Holdings, (ii) repay the remaining balance of $140.0 million outstanding under our existing credit facility and (iii) pay fees and expenses of approximately $2.5 million relating to our new credit facility.

        As of September 30, 2012, we had approximately $253.2 million of indebtedness outstanding under our existing credit facility with a weighted average interest rate of 4.5%. The revolving credit facility matures on June 10, 2016, and borrowings bear interest at a variable rate per annum equal to the lesser of LIBOR, plus the applicable margins ranging from 2.25% to 4.25%, or at a base rate, plus applicable margins ranging from 1.25% to 3.25%. Borrowings made under our credit facility within the last twelve months were used primarily to 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 Holdings 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 per common unit in this offering before expenses but after deducting underwriting discounts, commissions and structuring fees.

        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 structuring fees, to increase or decrease, respectively, by $8.4 million. In addition, we may also increase or decrease the number of common units we are offering. Each increase of 1.0 million common units offered by us, together with a concurrent $1.00 increase in the assumed public offering price of $20.00 per common unit, would increase net proceeds to us from this offering by approximately $28.0 million. Similarly, each decrease of 1.0 million common units offered by us, together with a concurrent $1.00 decrease in the assumed initial offering price of $20.00 per common unit, would decrease the net proceeds to us from this offering by approximately $26.1 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 our cash distribution to Holdings.

        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 the underwriters are lenders under our existing credit facility and will, in that respect, receive a portion of the proceeds from this offering through the repayment of borrowings outstanding under our credit facility. Please read "Underwriting."

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CAPITALIZATION

        The following table shows:

    the historical capitalization of Southcross Energy LLC, as of June 30, 2012; and

    the as adjusted capitalization of Southcross Energy Partners, L.P., as of June 30, 2012, giving effect to:

    the receipt and use of net proceeds of $168.7 million from this offering in the manner described in "Use of Proceeds";

    the entry into and borrowing of $150.0 million under our new credit facility and the use of such borrowings in the manner described in "Use of Proceeds"; and

    the other transactions described in "Summary—Recapitalization 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  
 
  Historical   As
Adjusted
 
 
  (in thousands)
 

Cash and cash equivalents

  $ 3,294   $ 3,294 (3)
           

Long-Term Debt:

             

Existing credit facility(1)

    214,535      

New credit facility

        150,000  
           

Total long-term debt (including current maturities)

    214,535     150,000  
           

Redeemable preferred units(2)

    18,073      

Redeemable preferred units—Series B(2)

    44,584      

Redeemable preferred units—Series C(2)

    30,059      

Preferred units(2)

    157,841      

Equity:

             

Common equity

    1,342      

Common units—public

        163,530  

Common units—Holdings

        35,520  

Subordinated units

        134,995  

General partner equity

        5,510  

Accumulated other comprehensive loss

    (264 )    

Accumulated deficit

    (29,580 )    
           

Total equity

    (28,502 )   339,555  
           

Total capitalization

  $ 436,590   $ 489,555  
           

(1)
As of September 30, 2012, we had approximately $253.2 million of indebtedness outstanding under our existing credit facility.

(2)
Represents preferred units in Southcross Energy LLC (Holdings), which will remain a part of Holdings' capitalization.

(3)
Reflects cash and cash equivalents after the repayment of $265.0 million of outstanding debt as of the expected closing date of this offering.

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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 $330.1 million, or $13.24 per unit. Net tangible book value excludes $1.7 million of net intangible assets and $7.8 million of other non-current 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

        $ 20.00  

Net tangible book value per unit before the offering(1)

  $ 13.35        

Decrease in net tangible book value per unit attributable to purchasers in the offering

    (0.11 )      
             

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

          13.24  
             

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

        $ 6.76  
             

(1)
Determined by dividing the number of units (3,213,713 common units, 12,213,713 subordinated units and the 2.0% general partner interest) held by our general partner and its affiliates, including Holdings, into the net tangible book value of our assets before the offering. Net tangible book value of our assets as of June 30, 2012 was $212.6 million, which is calculated as total assets of $492.5 million less total liabilities of $270.4 million, less net intangible assets of $1.7 million and other non-current assets of $7.8 million.

(2)
Determined by dividing the total number of units to be outstanding after this offering (12,213,713 common units, 12,213,713 subordinated units and the 2.0% general partner interest) 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 $7.76 and $5.76, 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)

    15,926     63.9 % $ 176,025     49.4 %

Purchasers in the offering

    9,000     36.1     180,000     50.6  
                   

Total

    24,926     100.0 % $ 356,025     100.0 %
                   

(1)
The units acquired by our general partner and its affiliates, including Holdings, consist of 3,213,713 common units, 12,213,713 subordinated units and the 2.0% general partner interest.

(2)
Assumes the underwriters' option to purchase additional common units is not exercised.

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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 consolidated financial statements and related notes and our Predecessor's historical combined financial statements and related notes included elsewhere in this prospectus.


General

    Rationale for Our Cash Distribution Policy

        Our partnership agreement requires us to distribute all of our available cash quarterly. Our cash distribution policy reflects our belief that our unitholders will be better served if we distribute, rather than retain, our available cash. Generally, our available cash is the sum of 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 as provided 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 may be subject to restrictions on distributions under our new credit facility or other debt agreements entered into in the future. Our new credit facility will contain financial tests and covenants that we must satisfy. These financial tests and covenants are described in "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Credit Facility." Should we be unable to satisfy these restrictions or if we are otherwise in default under our new credit facility, we will be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy.

    Our general partner will have the authority to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment or increase of those reserves could result in a reduction in cash distributions to our unitholders from the levels we currently anticipate pursuant to our stated cash distribution policy. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish. Any determination to establish cash reserves made by our general partner in good faith will be binding on our unitholders. Our partnership agreement provides that in order for a determination by our general partner to be considered to have been made in good faith, our general partner must subjectively believe that the determination is in our best interests.

    While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the 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 other than in certain limited circumstances where no unitholder approval is required. However, our

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      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 Holdings) after the subordination period has ended. At the closing of this offering, assuming no exercise of the underwriters' option to purchase additional common units, Holdings will own our general partner and approximately 26.3% of our outstanding common units and 100% of our outstanding subordinated units.

    Even if our cash distribution policy is not modified or revoked, the amount of cash that we distribute 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 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.

    We may lack sufficient cash to pay distributions to our unitholders for a number of reasons, including as a result of 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 general partner will not receive a management fee or other compensation for its management of us. However, under our partnership agreement, we are obligated to reimburse our general partner and its affiliates for all expenses incurred on our behalf. Our partnership agreement provides that our general partner will determine the amount of these reimbursed expenses. For the twelve months ending September 30, 2013, we estimate that these expenses will be approximately $26.3 million, which includes, among other items, compensation expense for all employees required to manage and operate our business.

    If we make distributions out of capital surplus, as opposed to operating surplus, any such distributions would constitute a return of capital and would result in a reduction in the minimum quarterly distribution and the target distribution levels. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels." We do not anticipate that we will make any distributions from capital surplus.

    Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.

    Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital

        Because we will distribute all of our available cash to our unitholders, we expect that we 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 intend to 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 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, and we do not anticipate there being limitations in our new 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

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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 the closing of this offering, the board of directors of our general partner will establish a minimum quarterly distribution of $0.40 per unit per quarter, or $1.60 per unit on an annualized basis, to be paid no later than 45 days after the end of each fiscal quarter beginning with the quarter ending December 31, 2012. This equates to an aggregate cash distribution of $10.0 million per quarter, or $40.1 million on an annualized basis, based on the number of common and subordinated units anticipated to be outstanding immediately after the closing of this offering, as well as our 2.0% general partner interest. We will adjust our first distribution for the period from the closing of this offering through December 31, 2012 based on the length of that period. 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 "—General—Limitations on Cash Distributions and Our Ability to Change our Cash Distribution Policy."

        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 Holdings 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 per common unit 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 common units or subordinated units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read "Use of Proceeds."

        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 and the number of unit equivalents represented by the 2.0% general partner interest that we anticipate will be outstanding immediately following the closing of this offering, and the aggregate distribution amounts payable on those units during the year following the closing of this offering at our minimum quarterly distribution rate of $0.40 per unit per quarter ($1.60 per unit on an annualized basis).

 
   
  Minimum Quarterly
Distributions
 
 
  Number of Units   One Quarter   Annualized  

Public Common Units

    9,000,000   $ 3,600,000   $ 14,400,000  

Holdings Units:

                   

Common Units

    3,213,713     1,285,485     5,141,940  

Subordinated Units

    12,213,713     4,885,485     19,541,940  

LTIP Participants Units(1)

    150,000     60,000     240,000  

General Partner Interest

    498,518     199,407     797,629  
               

Total

    25,075,944   $ 10,030,377   $ 40,121,509  
               

(1)
Assumes that in connection with the closing of this offering, the board of directors of our general partner will grant 150,000 phantom units with distribution equivalent rights to employees who provide services for us, including executive officers, pursuant to our long-term incentive plan. Please read "Management—Executive Compensation—2012 Long-Term Incentive Plan."

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        The subordination period generally will end and all of the subordinated units will convert into an equal number of common units if we have earned and paid at least $1.60 on each outstanding common and subordinated unit and the corresponding distribution on our general partner's 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2015. The subordination period will automatically terminate and all of the subordinated units will convert into an equal number of common units if we have earned and paid at least $2.40 (150% of the annualized minimum quarterly distribution) on each outstanding common and subordinated unit and the corresponding distributions on our general partner's 2.0% interest and incentive distribution rights for any four consecutive quarter period ending on or after December 31, 2013; provided that we have paid at least the minimum quarterly distribution from operating surplus on each outstanding common unit and subordinated unit for each quarter in that four-quarter period and the corresponding distribution on our general partner's 2.0% interest. Please read the "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 in some circumstances 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 and the corresponding distributions on our general partner's 2.0% interest, we will use this excess available cash to pay any distribution arrearages on the common units related to prior quarters before any cash distribution is made to holders of the 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 December 31, 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 $1.60 per unit for the twelve months ending September 30, 2013.

        In those sections, we present two tables, consisting of:

    "Unaudited Pro Forma Cash Available for Distribution," in which we present the amount of cash we would have had available for distribution on a pro forma basis for our fiscal year ended December 31, 2011 and the twelve months ended June 30, 2012, derived from our unaudited pro forma financial data that is included elsewhere in this prospectus, which includes the pro forma effect of the EAI acquisition as if such transaction occurred on January 1, 2011, as adjusted to reflect incremental annual general and administrative expenses associated with being a publicly traded partnership; and

    "Estimated Cash Available for Distribution," which supports our belief that we will be able to generate the sufficient estimated cash available for distribution to pay the minimum quarterly distribution on all units for the twelve months ending September 30, 2013.

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Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2011 and the Twelve Months Ended June 30, 2012

        If we had completed this offering on January 1, 2011, our unaudited pro forma cash available for distribution would have been approximately $18.0 million for the year ended December 31, 2011. This amount would have been sufficient to pay only 91.0% of the aggregate minimum quarterly distribution on our common units during that period, and we would have not been able to pay any distributions on our subordinated units during that period.

        If we had completed this offering on July 1, 2011, our unaudited pro forma cash available for distribution would have been approximately $21.3 million for the twelve months ended June 30, 2012. This amount would have been sufficient to pay the annualized minimum quarterly distribution of $1.60 per unit on our common units during that period but only 7.8% of the aggregate minimum quarterly distribution on our subordinated units during that period.

        Our unaudited pro forma available cash for the year ended December 31, 2011 and the twelve months ended June 30, 2012 takes into account $2.2 million of incremental annual general and administrative expenses that we expect to incur as a result of becoming a publicly traded partnership. This amount is an estimate, and our general partner will ultimately determine the actual amount of these incremental annual general and administrative expenses to be reimbursed by us in accordance with our partnership agreement. Incremental annual 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 NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees, outside director fees and director and officer insurance expenses. These expenses are not reflected in our or our Predecessor's historical financial statements.

        Our estimate of incremental annual general and administrative expenses is based upon currently available information. The adjusted amounts below do not purport to present our results of operations had this offering been completed as of the date indicated. In addition, cash available to pay distributions is primarily a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma available cash 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 the dates indicated.

        The following table illustrates, on a pro forma 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 had been completed at the beginning of such period. Each of the adjustments reflected or presented below is explained in the footnotes to such adjustments.

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Unaudited Pro Forma Cash Available for Distribution

 
  Year Ended
December 31, 2011
  Twelve Months Ended
June 30, 2012
 
 
  (in thousands, except
per unit data)

 

Pro Forma Net Income

  $ 7,476   $ 12,842  

Add:

             

Depreciation and amortization expense

    13,200     14,295  

Interest expense, net(1)

    6,383     4,514  

Loss on extinguishment of debt

    3,240      

Non-cash equity compensation

        146  

Transaction costs(2)

    203      

Income tax expense(3)

    261     351  
           

Pro Forma Adjusted EBITDA(4)

  $ 30,763   $ 32,148  

Less:

             

Incremental annual general and administrative expenses of being a publicly traded partnership(5)

    2,200     2,200  

Cash interest expense, net of interest income(6)

    5,466     3,611  

Cash tax expense

    272     313  

Expansion capital expenditures(7)

    140,439     174,338  

Maintenance capital expenditures(8)

    5,423     5,325  

Add:

             

Management fee(9)

    600     600  

Borrowings to fund expansion capital expenditures

    140,439     174,338  
           

Pro Forma Cash Available for Distribution

  $ 18,002   $ 21,299  
           

Implied Cash Distribution at the Minimum Quarterly Distribution Rate:

             

Annualized minimum quarterly distribution per unit

  $ 1.60   $ 1.60  

Distributions to public common unitholders

    14,400     14,400  

Distributions to Holdings—common units

    5,142     5,142  

Distributions to Holdings—subordinated units

    19,542     19,542  

Distributions to LTIP participants(10)

    240     240  

Distributions to general partner

    798     798  

Total distributions to unitholders and general partner

  $ 40,122   $ 40,122  
           

Excess (shortfall)

  $ (22,120 ) $ (18,823 )
           

Percent of minimum quarterly distribution payable to common unitholders

    91.0 %   100.0 %

Percent of minimum quarterly distribution payable to subordinated unitholders

        7.8 %

(1)
Represents interest expense with cost of borrowing of 3.5% on the outstanding debt balance of $150.0 million as if we had entered into our new credit facility on January 1, 2011, plus applicable commitment and deferred financing fees, less capitalized interest.

(2)
Represents costs relating to the acquisition of EAI on September 1, 2011.

(3)
Represents Texas state tax on gross margin.

(4)
For a definition of Adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read "Selected Historical and

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    Pro Forma Financial and Operating Data—Non-GAAP Financial Measures," and for a discussion of how we use Adjusted EBITDA to evaluate our operating performance, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations."

(5)
Represents estimated cash expense associated with being a publicly traded partnership, such as expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees, outside director fees and director and officer insurance expenses.

(6)
Pro forma cash interest paid was reduced by $1.8 million to eliminate the impact of a payment in early January 2011 for interest expense incurred in 2010, and reflects four quarters of cash interest expense, net of interest income.

(7)
Expansion capital expenditures include the acquisition of equipment, or the construction, development or acquisition of additional pipeline or treating capacity or compression capacity to the extent that such capital expenditures are expected to expand our long-term operating capacity or operating income. Expansion capital expenditures have been adjusted by a decrease of $10.2 million and $10.7 million, which represents net changes in amounts outstanding in accounts payable as of December 31, 2011 and June 30, 2012, respectively.

(8)
Maintenance capital expenditures are made to maintain our long-term operating income or operating capacity. We expect that a primary component of maintenance capital expenditures will include expenditures for routine equipment and pipeline maintenance or replacement due to obsolescence.

(9)
Represents a fee paid to Charlesbank that will no longer be paid when we become a publicly traded partnership.

(10)
Assumes that in connection with the closing of this offering, the board of directors of our general partner will grant 150,000 phantom units with distribution equivalent rights to employees who 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 $48.1 million. This amount would exceed by $8.0 million the amount needed to pay the total annualized minimum quarterly distribution of $40.1 on all of our 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.

        We do not, as a matter of course, make public projections as to future operations, earnings or other results. However, management has prepared the forecast of estimated cash available for distribution and related assumptions and considerations set forth below to substantiate our belief that we will have sufficient cash available for distribution to allow us to pay the total annualized minimum quarterly distribution on all of our outstanding 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. This forecast is a forward-looking statement and should be read together with our historical consolidated financial statements and the accompanying notes, and our Predecessor's historical combined financial statements and the accompanying notes included elsewhere in this prospectus, as well as "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 guidelines established by the American Institute of Certified Public Accountants

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with respect to prospective financial information, but, in the view of our management, is substantially consistent with those guidelines and 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 can generate the minimum estimated cash available for distribution necessary to pay the total annualized minimum quarterly distribution on all of our outstanding 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, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

        The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. Neither our independent registered public accounting firm nor any other independent accountants have compiled, examined, or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability. They therefore 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 the minimum estimated cash available for distribution necessary to pay the total annualized minimum quarterly distribution on all of our outstanding 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.

        We are providing the forecast of estimated cash available for distribution and related assumptions set forth below to supplement our historical consolidated financial statements and our Predecessor's historical combined financial statements 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 on all of our outstanding 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. 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. Therefore, 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 on all of our outstanding 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 should not be regarded as a representation by us, the underwriters or any other person that we will make such distributions. Therefore, you are cautioned not to place undue reliance on this information.

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Estimated Cash Available For Distribution

 
  Quarter Ending    
 
 
  Twelve Months
Ending
September 30,
2013
 
 
  December 31,
2012
  March 31,
2013
  June 30,
2013
  September 30,
2013
 
 
  (in thousands, except per unit data)
 

Total Revenue

  $ 177,398   $ 226,816   $ 234,888   $ 239,765   $ 878,867  

Expenses:

                               

Cost of natural gas and liquids sold

    153,437     198,158     205,699     210,209     767,503  

Operations and maintenance

    8,064     9,821     9,967     9,985     37,837  

Depreciation and amortization

    5,176     5,879     6,045     6,017     23,117  

General and administrative(1)

    3,491     3,499     3,631     3,660     14,281  
                       

Total expenses

    170,168     217,357     225,342     229,871     842,738  

Income from operations

  $ 7,230   $ 9,459   $ 9,546   $ 9,894   $ 36,129  

Interest expense, net

    (1,274 )   (1,503 )   (1,608 )   (1,696 )   (6,081 )

Income tax expense(2)

    (111 )   (132 )   (135 )   (137 )   (515 )
                       

Net income

  $ 5,845   $ 7,824   $ 7,803   $ 8,061   $ 29,533  
                       

Plus:

                               

Depreciation and amortization

    5,176     5,879     6,045     6,017     23,117  

Interest expense, net

    1,274     1,503     1,608     1,696     6,081  

Income tax expense(2)

    111     132     135     137     515  
                       

Adjusted EBITDA(3)

  $ 12,406   $ 15,338   $ 15,591   $ 15,911   $ 59,246  
                       

Less:

                               

Cash interest expense, net of interest income

    (1,061 )   (1,385 )   (1,490 )   (1,578 )   (5,514 )

Cash tax expense

    (111 )   (132 )   (135 )   (137 )   (515 )

Expansion capital expenditures(4)

    (50,485 )   (29,595 )   (16,433 )   (25,208 )   (121,721 )

Maintenance capital expenditures(5)

    (1,405 )   (1,405 )   (1,155 )   (1,155 )   (5,120 )

Add:

                               

Available cash and borrowings to fund expansion capital expenditures

    50,485     29,595     16,433     25,208     121,721  

Estimated cash available for distribution

  $ 9,829   $ 12,416   $ 12,811   $ 13,041   $ 48,097  
                       

Implied cash distribution at the minimum quarterly distribution rate:

                               

Annualized minimum quarterly distribution per unit

  $ 0.40   $ 0.40   $ 0.40   $ 0.40   $ 1.60  

Distributions to public common unit holders

    3,600     3,600     3,600     3,600     14,400  

Distributions to Holdings—common units

    1,285     1,285     1,285     1,285     5,142  

Distributions to Holdings—subordinated units

    4,885     4,885     4,885     4,885     19,542  

Distributions to LTIP participants(6)

    60     60     60     60     240  

Distributions to general partner

  $ 200   $ 200   $ 200   $ 200   $ 798  

Total distribution to our unitholders and general partner

  $ 10,030   $ 10,030   $ 10,030   $ 10,030   $ 40,122  

Excess of cash available for distribution over total annualized minimum quarterly distributions            

  $ (200 ) $ 2,386   $ 2,781   $ 3,011   $ 7,975  

(1)
Includes $2.2 million of estimated incremental annual cash expense associated with being a publicly traded partnership, such as expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; outside director fees and director and officer insurance expenses. Excludes any expenses we may incur related to non-cash equity compensation.

(2)
Represents Texas state tax on gross margin.

(3)
For a definition of Adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read "Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures," and for a discussion of how we use Adjusted EBITDA to evaluate our operating performance, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations."

(4)
Expansion capital expenditures include the acquisition of equipment, or the construction, development or acquisition of additional pipeline or treating capacity or compression capacity to the extent that such capital expenditures are expected to expand our long-term operating capacity or operating income.

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(5)
Maintenance capital expenditures are made to maintain our long-term operating income or operating capacity. We expect that a primary component of maintenance capital expenditures will include expenditures for routine equipment and pipeline maintenance or replacement due to obsolescence.

(6)
Assumes that in connection with the closing of this offering, the board of directors of our general partner will grant 150,000 phantom units with distribution equivalent rights to employees who provide services for us, including executive officers, pursuant to our long-term incentive plan. Please read "Management—Executive Compensation—2012 Long-Term Incentive Plan."


Assumptions and Considerations

        Set forth below are the material assumptions that we have made in order to demonstrate our ability to generate the minimum estimated 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 and sensitivity analysis

        We currently expect that opportunities to process liquids-rich natural gas in the Eagle Ford shale area, which is served by our South Texas assets, will be the primary driver of our near-term growth. We completed construction and commenced operations in July 2012 of a 200 MMcf/d cryogenic processing plant in Refugio County, Texas, which we refer to as our Woodsboro processing plant, that significantly expands our South Texas processing capacity. We are increasing our NGL capacity by installing our Bonnie View fractionation plant that we expect to be fully operational in November 2012 with capacity of 11,500 Bbl/d. We recently announced an expansion of this capacity by 11,000 Bbl/d to 22,500 Bbl/d through the installation of an additional tower that we expect to be completed in January 2013. In addition, our McMullen pipeline expansion, completed in September 2011, improves our ability to transport liquids-rich gas from producers in the Eagle Ford shale area to Woodsboro. In the first quarter of 2013, we expect to complete a 57-mile pipeline that will bring additional supply of liquids-rich gas from Dewitt and Karnes Counties in the Eagle Ford shale area to our Woodsboro processing plant. These capacity expansions will enable us to gather and process additional volumes of natural gas and fractionate and market more NGLs by commencing deliveries under contracts with producers that have been secured or are nearing expected execution. Accordingly, our forecasted results are not directly comparable with historical periods. We expect that processing and fractionation capacities that are coming on-line at our Woodsboro and Bonnie View plants will enable us to produce greater economic value from larger volumes of liquids-rich natural gas that we process and greater recovery of NGLs from our fractionation operations as compared to our current operations.

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        The following tables present the actual capacity of both our pipelines and processing and fractionation plants as of June 30, 2012 and their anticipated capacity as of March 31, 2013. We have elected to present projected information as of March 31, 2013 in order to illustrate our anticipated capacities after we have placed in service the growth capital projects that are expected to increase our distributable cash flow during the forecast period.

 
  As of
June 30, 2012
  Expected
As of March 31, 2013(1)
 
 
  Miles   Approximate
Design Capacity
(MMcf/d)
  Miles   Approximate
Design Capacity
(MMcf/d)
 

Pipeline systems

                         

South Texas

                         

Gulf Coast Systems

    1,160     405     1,282  (2)   795  (2)

Gregory

    266     135     266     135  

Conroe

    19     50     19     50  
                   

South Texas Total

    1,445     590     1,567     980  

Mississippi

   
626
   
345
   
626
   
345
 

Alabama

    519     375     519     375  
                   

Total Pipelines

    2,590     1,310     2,712     1,700  
                   

(1)
As reflected in our forecast for the twelve months ending September 30, 2013.

(2)
Includes new DeWitt and Karnes Pipeline extension which is due to be fully in service by February 2013 and the addition of a pipeline acquisition completed in September 2012.

 
  As of June 30, 2012   Expected
As of March 31, 2013(1)
 
 
  Approximate
Design Capacity
(MMcf/d)
  Fractionation
Capacity (Bbls/d)
  Approximate
Design Capacity
(MMcf/d)
  Fractionation
Capacity (Bbls/d)
 

Processing/Fractionation plants

                         

Gregory Processing

    135         135      

Gregory Fractionation

        4,800         4,800  

Conroe

    50         50      

Woodsboro

    200 (2)         200        

Bonnie View(3)

                22,500  
                   

Total

    385     4,800     385     27,300  
                   

(1)
As reflected in our forecast for the twelve months ending September 30, 2013.

(2)
Our Woodsboro processing plant entered service in July 2012.

(3)
The initial phase of the Bonnie View plant is expected to be fully operational in November 2012 with capacity of 11,500 Bbls/d; the second phase is expected to provide an additional 11,000 Bbls/d of capacity and is forecasted to be complete in January 2013.

        This forecast for the twelve months ending September 30, 2013 anticipates that our natural gas supply will come from volumes supplied under existing contracts, from contractual increases in volumes once our capacity expansions are complete, from new contracts we have recently executed and from new supply contracts that we are currently negotiating with existing or new customers. This forecast also includes twelve months of operational results from the EAI and MONCO acquisitions and a full year's benefit from new supply contracts enabled by our McMullen pipeline expansion.

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        We estimate that our realized price of natural gas and NGLs for the twelve months ending September 30, 2013 will average $3.86 per MMBtu and $0.81 per gallon, respectively, and represent a decrease of 4.6% and 40.2%, respectively, from the prices that we realized during the year ended December 31, 2011 and an increase/(decrease) of 22.9% and (32.0)%, respectively, from the prices that we realized during the twelve months ended June 30, 2012. These forecasts for the realized price of natural gas and NGLs were derived based upon forward NYMEX natural gas prices as of September 28, 2012 and the projections as of October 4, 2012 of PIRA Energy Group, an international energy consulting firm specializing in global energy market analysis and intelligence, for NGL prices, respectively, as adjusted by management for various discounts or premiums to reflect transportation, quality and regional price adjustments.

        The primary factors that are expected to increase the amount of cash available for distribution during the forecast period compared to historical performance include the growth in transported and processed gas through our systems, an increase in our overall processing capacity which will enable us to capture more economic value from gas entering our system, and the beginning of production of purity NGLs at our Bonnie View fractionation plant. System throughput as well as natural gas and NGL prices are key factors that influence whether the amount of cash available for distribution for the twelve months ending September 30, 2013 will be above or below our forecast. For example, if all other assumptions are held constant, a five percent (5.0%) increase or decrease in volumes across all of our assets above or below forecasted levels would result in a $4.2 million increase or $4.0 million decrease, respectively, in cash available for distribution. A five percent (5.0%) increase or decrease in the price of natural gas above or below forecasted levels would result in a $0.6 million decrease or $0.6 million increase, respectively, in cash available for distribution. This inverse relationship between an increase in natural gas prices and the resulting decrease in cash available for distribution occurs because our processing margins decline as the cost of natural gas entering our processing plants increases. In contrast, our gas sales margins are largely unaffected by changes in natural gas prices because a significant portion of our contracts are fixed fee and fixed spread. A five percent (5.0%) increase or decrease in the price of NGLs below forecasted levels, would result in a $1.8 million increase or decrease in cash available for distribution, respectively. A decrease in forecasted cash flow of greater than $8.0 million would result in our generating less than the minimum cash required to pay distributions during the forecast period.

    Throughput and processing volumes

        We forecast that our average daily throughput of natural gas per day will be 727,577 MMBtu and that we will deliver an average daily volume of 892.9 Mgal of NGLs for the twelve months ending September 30, 2013, compared to an average daily volume of 506,975 MMBtu and 215.5 Mgal, respectively, for the year ended December 31, 2011 and an average daily volume of 573,086 MMBtu and 301.1 Mgal, respectively, for the twelve month period ended June 30, 2012.

        Our forecast for the increase in the daily throughput of natural gas is 220,602 MMBtu, or 43.5%, more than the year ended December 31, 2011, and 154,491 MMBtu, or 27.0%, more than the twelve months ended June 30, 2012. We expect that our South Texas natural gas throughput will average 518,374 MMBtu per day compared to 363,545 MMBtu per day and 382,103 MMbtu per day for the year ended December 31, 2011 and the twelve months ended June 30, 2012, respectively. These increases reflect the impact of new contracts entered into or volume expansion of existing contracts as a result of the McMullen pipeline extension (that was completed in September 2011) and the new DeWitt and Karnes Counties pipeline that is due to be completed in the first quarter of 2013, both of which will provide enhanced access to producers in the Eagle Ford shale area. Of the 136,271 MMBtu per day increase in South Texas volumes compared to the twelve months ended June 30, 2012, approximately 79.7% is expected from existing contracts or contracts being finalized, and 20.3% is expected from contracts currently under negotiation with new and existing customers. Our Mississippi and Alabama natural gas throughput is expected to average 209,203 MMBtu per day for the twelve

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months ending September 30, 2013 compared to 143,430 MMBtu per day for the year ended December 31, 2011 and 190,983 MMBtu per day for the twelve months ended June 30, 2012. Of the 18,220 MMBtu per day increase in Mississippi and Alabama compared to the twelve months ended June 30, 2012, 19,053 MMBtu per day is due to the benefit of a full year of volume from our EAI acquisition. Without the benefit of the EAI acquisition, we would have expected modest declines in throughput in our Mississippi and Alabama business due to our assumption that gas supply in areas utilizing conventional drilling in Mississippi and Alabama is expected to show a slight decline in volume for the twelve months ending September 30, 2013 compared to the year ended December 31, 2011 and twelve months ended June 30, 2012.

        The table below outlines the components of our estimated NGL volumes for the twelve months ending September 30, 2013 compared to the actual volumes for the year ended December 31, 2011 and the twelve months ended June 30, 2012.

 
  Average Daily Volumes of NGLs Delivered (in Mgal)  
 
  Historical   Forecasted  
 
  Year Ended
December 31,
2011
  Twelve
Months
Ended
June 30,
2012
  Twelve
Months
Ending
September 30,
2013
 

Woodsboro plant/Bonnie View plant

            682.6  

Existing facilities (including Formosa)

    215.5     301.1     210.3  
               

Total

    215.5     301.1     892.9  
               

        Our average volume of NGLs delivered per day is expected to be 892.9 Mgal for the twelve months ending September 30, 2013, an increase of 314.3% compared to 215.5 Mgal for the year ended December 31, 2011, and an increase of 196.5% compared to 301.1 Mgal for the twelve months ended June 30, 2012. This increase will be driven primarily by four factors: (i) our new 200 MMcf/d Woodsboro processing plant that began operations in July 2012, which significantly increases our processing capacity; (ii) new sources of gas from the Eagle Ford shale area entering our McMullen pipeline extension and our DeWitt and Karnes Counties pipeline which is expected to be completed in the first quarter of 2013 that we expect to process at our Woodsboro processing plant; (iii) greater fractionation capacity arising from our Bonnie View fractionation plant as compared to our contracted capacity at the Formosa plant; and (iv) incremental NGL volumes from existing sources of gas that will be transferred to our Woodsboro processing plant where we will realize a larger volume of NGLs produced per equivalent Mcf than under our contract at the Formosa plant that will expire in January 2013.

    Revenue

        We estimate that we will generate total revenue of $878.9 million for the twelve months ending September 30, 2013, compared to $523.1 million for the year ended December 31, 2011 and $502.0 million for the twelve months ended June 30, 2012. The expected increase of $376.9 million, or 75.1%, compared to the twelve months ended June 30, 2012 primarily relates to higher expected natural gas and NGL volumes, offset partially by lower NGL prices on our systems as described above.

    Cost of natural gas and NGLs sold

        We estimate that the cost of natural gas and NGLs sold for the twelve months ending September 30, 2013 will be $767.5 million, compared to $460.6 million for the year ended December 31, 2011 and $429.7 million for the twelve months ended June 30, 2012. The expected increase of $337.8 million, or 78.6%, compared to the twelve months ended June 30, 2012 is primarily

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due to expected higher natural gas and NGL volumes on our systems, partially offset by lower NGL prices, as further described above.

    Gross operating margin

        We estimate that we will generate gross operating margin of $111.4 million for the twelve months ending September 30, 2013, compared to $62.6 million for the year ended December 31, 2011 and $72.3 million for the twelve months ended June 30, 2012. The table below outlines the components of our estimated and actual gross operating margin for the twelve months ending September 30, 2013, the year ended December 31, 2011 and the twelve months ended June 30, 2012.

 
  Historical   Forecasted  
 
  Year Ended
December 31, 2011
  Twelve Months Ended
June 30, 2012
  Twelve Months Ending
September 30, 2013
 
 
  Gross
Operating
Margin
  Percent
of Total
Gross
Operating
Margin
  Gross
Operating
Margin
  Percent
of Total
Gross
Operating
Margin
  Gross
Operating
Margin
  Percent
of Total
Gross
Operating
Margin
 
 
  (in thousands)
   
  (in thousands)
   
  (in thousands)
   
 

Fixed-fee

  $ 32,340     51.7 % $ 41,142     56.9 % $ 59,390     53.3 %

Fixed-spread

    12,204     19.6     13,006     18.0     28,046     25.2  

POP-floor(1)

    2,340     3.7     1,743     2.4     334     0.3  
                           

Sub-total

  $ 46,884     75.0 % $ 55,891     77.3 % $ 87,770     78.8 %

POP

    4,339     6.9     4,432     6.1     21,684     19.5  

POP-upgrade(2)

    11,346     18.1     11,997     16.6     1,910     1.7  
                           

Total

  $ 62,569     100.0 % $ 72,320     100.0 % $ 111,364     100.0 %
                           

(1)
Represents that portion of gross operating margin under the processing arrangement with Formosa that is derived on a fixed-spread basis. For more information about our contract with Formosa, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Our Operations—Percent-of-Proceeds."

(2)
Represents that portion of gross operating margin under the processing arrangement with Formosa that is derived from a fixed percentage of the value of the NGLs delivered and the residue gas. This margin will vary with the relative prices of NGLs and natural gas and is not realized when the price of NGLs is low relative to the price of natural gas.

        We estimate that our forecasted increase of 43.1% in natural gas volumes for the twelve months ending September 30, 2013, compared to the twelve months ended June 30, 2012 will result in higher margins for those contracts that are not price sensitive of $81.2 million for the forecast period, as compared to $55.9 million for the twelve months ended June 30, 2012. The addition of the 200 MMcf/d Woodsboro processing plant will increase both our absolute margins through the significantly higher processing capacity, which enables us to handle new sources of liquids-rich natural gas that is being supplied to our pipeline system, and the percentage contribution of our processing contracts to our total margin. As the volume at our Woodsboro processing plant increases, we will reduce the amount of natural gas sent to Formosa for processing and, therefore, reduce the margins related to our Formosa contract (POP floor and POP upgrade) and increase our POP margins. Our ability to process more gas through our Woodsboro processing plant, the retention of a greater portion of the processing margins in the forecast period from our NGL production and the impact of the Bonnie View fractionation plant are the primary drivers for our estimated POP margins of $21.8 million for the twelve months ending September 30, 2013, compared to $4.3 million for the year ended December 31, 2011 and $4.4 million for the twelve months ended June 30, 2012. As we bring additional new supplies of natural gas to our Woodsboro processing plant by adding pipeline capacity during the first quarter of 2013, we expect to increase both our fixed fee and POP margins.

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    Operations and maintenance expense

        We forecast operations and maintenance expenses of $37.8 million for the twelve months ending September 30, 2013 compared to $24.7 million for the year ended December 31, 2011 and $30.0 million for the twelve months ended June 30, 2012. We anticipate continuation of our historical level of these expenses, adjusted for the timing of pipeline integrity costs and inflation, in the forecast period, with added expenses for the operation of incremental assets including our Woodsboro and Bonnie View plants.

 
  Historical   Forecasted  
 
  Year
Ended
December 31,
2011
  Twelve
Months
Ended
June 30,
2012
  Twelve
Months
Ending
September 30,
2013
 
 
  (in thousands)
 

Woodsboro processing plant

  $   $ 691   $ 8,028  

Bonnie View fractionation plant

            2,266  

EAI acquisition

    1,228     2,824     3,714  

Other

    23,479     26,478     23,829  
               

Total

  $ 24,707   $ 29,993   $ 37,837  
               

    General and administrative expense

        We estimate that G&A expense for the twelve months ending September 30, 2013 will be $14.3 million, compared to $8.9 million for the year ended December 31, 2011 and $10.3 million for the twelve months ended June 30, 2012. This increase will be primarily attributable to the estimated $2.2 million of incremental annual G&A expense that we expect to incur as a result of being a publicly traded partnership, as well as increased wages and benefits associated with additional personnel hired as part of our growth plans and additional infrastructure required to construct and manage additional assets. G&A expense is comprised primarily of fixed costs and is not expected to vary significantly with increases or decreases in revenue or gross operating margin. G&A expense for the year ended December 31, 2011 and the twelve months ended June 30, 2012 includes a management fee of $50,000 per month that we paid to Charlesbank. Following the completion of this offering, we will no longer be required to pay this fee to Charlesbank.

    Depreciation and amortization expense

        We estimate that depreciation and amortization expense for the twelve months ending September 30, 2013 will be $23.1 million compared to $12.3 million for the year ended December 31, 2011 and $14.1 million for the twelve months ended June 30, 2012. Estimated depreciation expense is based on depreciable asset lives and depreciation methodologies consistent with our historical practice. The increase in depreciation expense is expected to be primarily attributable to additional depreciation associated with capital projects that were completed in 2011 and the first nine months of 2012 or that we expect to place in service during the twelve months ending September 30, 2013. Depreciation expenses are derived from asset value and useful life, and therefore are not expected to vary with increases or decreases in revenue and gross operating margin.

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    Capital expenditures

        We estimate that total capital expenditures for the twelve months ending September 30, 2013 will be $126.8 million compared to $156.0 million for the year ended December 31, 2011 and $190.4 million for the twelve months ended June 30, 2012. Our estimate is based on the following assumptions:

    We estimate that maintenance capital expenditures for the twelve months ending September 30, 2013 will total $5.1 million, compared to $5.3 million for the year ended December 31, 2011 and $5.3 million for the twelve months ended June 30, 2012.

    We estimate that growth capital expenditures for the twelve months ending September 30, 2013 will be $121.7 million, compared to $150.7 million for the year ended December 31, 2011 and $185.1 million for the twelve months ended June 30, 2012. These expenditures are comprised of growth capital projects that we anticipate pursuing during the forecast period. Once fully in service, we expect that the first four projects listed below will add $19.4 million in gross operating margin on an annualized basis as of the end of the forecast period, of which $10.9 million in gross operating margin is reflected in this forecast. The fifth and sixth projects listed below are not due to be completed until the fourth quarter 2013 or later and will have no material impact on gross operating margin during the forecast period. The capital projects that we expect to undertake in our forecast period include:

    constructing 57 miles of new pipeline to bring additional supply from DeWitt and Karnes Counties in the Eagle Ford shale area to our Woodsboro processing plant;

    constructing a lateral pipeline in Karnes County to bring additional supplies of liquids-rich gas to our Woodsboro processing plant;

    increasing the capacity of our Bonnie View fractionation plant by 11,000 Bbl/d;

    enhancing efficiency of recovery of NGLs at our Woodsboro processing plant;

    constructing new facilities to increase our capacity to produce and market NGLs and transport purity NGL products for our customers; and

    beginning construction of a second processing plant at Woodsboro along with additional pipelines to provide incremental gas supply.

    Financing

        We estimate that interest expense will be approximately $6.1 million (including approximately $0.5 million in non-cash interest expense related to deferred financing fees) for the twelve months ending September 30, 2013, compared to approximately $5.4 million for the year ended December 31, 2011 and $5.7 million for the twelve months ended June 30, 2012. Our estimate of interest expense for the forecast period is based on the following assumptions:

    We will have debt outstanding under our new credit facility as of the closing of this offering of $150.0 million; and

    We will have average outstanding borrowings during the forecast period of $196.4 million, including borrowings to finance our expansion capital expenditures, with an assumed weighted average effective interest rate of approximately 3.1%. This effective interest rate is lower than our expected cost of borrowing of 3.5% due to the level of capitalized interest that we expect to incur.

    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, capital or insurance markets or general economic conditions.

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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

    General

        Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 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 December 31, 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 credit needs);

    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 $0.40 per unit, or $1.60 on an annualized basis, to the extent we have sufficient

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

    General Partner Interest and Incentive Distribution Rights

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

        Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from operating surplus (as defined below) in excess of $0.46 per unit per quarter. The maximum distribution of 50.0% includes distributions paid to our general partner on its 2.0% general partner interest and assumes that our general partner maintains its general partner interest at 2.0%. The maximum distribution of 50.0% does not include any distributions that our general partner may receive on any limited partner units that it owns. Please see "—General Partner Interest and Incentive Distribution Rights" for additional information.


Operating Surplus and Capital Surplus

    General

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

        Operating Surplus    We define operating surplus as:

    $35.0 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 $35.0 million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

        We define interim capital transactions as (i) borrowings, refinancings or refundings of indebtedness (other than working capital borrowings and items purchased on open account in the ordinary course of business) and sales of debt securities, (ii) sales of equity securities, (iii) sales or other dispositions of assets, other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and sales or other dispositions of assets as part of ordinary course asset retirements or replacements, (iv) capital contributions received and (v) corporate reorganizations or restructurings.

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

    repayments of working capital borrowings where such borrowings have previously been deemed to have been repaid (as described above);

    payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than working capital borrowings;

    expansion capital expenditures;

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

    distributions to our partners;

    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; or

    any other expenditures or payments using the proceeds of this offering that are described in "Use of Proceeds."

        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 long-term operating income or operating capacity. We expect that a primary component of maintenance capital expenditures will include expenditures 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 distributions on equity 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.

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


Subordination Period

    General

        Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.40 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 December 31, 2015 that each of the following tests are met:

    distributions of available cash from operating surplus on each of the outstanding common and subordinated units and the related distribution on the general partner interest equaled or exceeded $1.60 (the annualized minimum quarterly distribution), plus the related distributions on the incentive distribution rights, 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 $1.60 (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 December 31, 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 equaled or exceeded $2.40 (150.0% of the annualized minimum quarterly distribution) 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) $2.40 (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;

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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;

    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

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    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

    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;

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        then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our 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 $0.46 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 $0.50 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 $0.60 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

  $0.40     98.0 %   2.0 %

First Target Distribution

  $0.40 up to $0.46     98.0 %   2.0 %

Second Target Distribution

  above $0.46 up to $0.50     85.0 %   15.0 %

Third Target Distribution

  above $0.50 up to $0.60     75.0 %   25.0 %

Thereafter

  above $0.60     50.0 %   50.0 %


General Partner's Right to Reset Incentive Distribution Levels

        Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner transfers all or a portion of our incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made. Our general partner's right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the Conflicts Committee, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the four consecutive fiscal quarters immediately preceding such time and the amount of each such distribution did not exceed adjusted operating surplus for such quarter, respectively. If our general partner and its affiliates are not

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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 amount of cash distributed per common unit during each of these two quarters.

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

    first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives an amount equal to 115.0% of the reset minimum quarterly distribution for that quarter;

    second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives an amount per unit equal to 125.0% of the reset minimum quarterly distribution for the quarter;

    third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the quarter; and

    thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

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

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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 $0.65.

 
   
   
  Marginal Percentage Interest
In Distributions
  Quarterly
Distributions
per Unit
Following
Hypothetical
Reset
 
 
  Quarterly Distribution
per Unit Prior to Reset
  Unitholders   2% General
Partner
Interest
  Incentive
Distribution
Rights
 

Minimum Quarterly Distribution

                 $0.40     98.0 %   2.0 %                  $0.6500      

First Target Distribution

             $0.40   up to $0.46     98.0 %   2.0 %               up to $0.7475     (1)

Second Target Distribution

  above $0.46   up to $0.50     85.0 %   2.0 %   13.0 %         above $0.7475     (1),

                                    up to $0.8125     (2)

Third Target Distribution

  above $0.50   up to $0.60     75.0 %   2.0 %   23.0 %         above $0.8125     (2),

                                    up to $0.9750     (3)

Thereafter

      above $0.60     50.0 %   2.0 %   48.0 %         above $0.9750     (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 24,427,425 common units outstanding, our general partner has maintained its 2.0% general partner interest and the average distribution to each common unit would be $0.65 for the two quarters prior to the reset. For the purpose of the following table, the 150,000 phantom units with distribution equivalent rights that are expected to be granted to employees in connection with this offering will be treated as common units.

 
   
   
  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
 
 
  (dollars in thousands, except per unit amounts)
 

Minimum Quarterly Distribution

  $0.40   $ 9,830   $ 200   $   $ 200   $ 10,030  

First Target Distribution

  $0.40 up to $0.46     1,475     30         30     1,505  

Second Target Distribution

  above $0.46 up to $0.50     983     24     150     174     1,157  

Third Target Distribution

  above $0.50 up to $0.60     2,458     66     754     820     3,277  

Thereafter

  above $0.60     1,229     49     1,180     1,229     2,458  
                           

      $ 15,975   $ 369   $ 2,084   $ 2,453   $ 18,428  
                           

        The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, with respect to the quarter in which the reset occurs. The table reflects that, as a result of the reset, there would be 27,633,241 common units outstanding, our general partner's 2.0% interest has been maintained, and the average distribution to each common unit would be $0.65. 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 $2.1 million, by (ii) the average available cash distributed on each common unit for the two quarters prior to the reset as shown in the

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table above, or $0.65. For the purpose of the following table, the 150,000 phantom units with distribution equivalent rights that are expected to be granted to employees in connection with this offering will be treated as common units.

 
   
   
   
  Cash Distribution To General
Partner After Reset
   
 
 
   
   
  Cash
Distributions
to Common
Unitholders
After Reset
   
 
 
  Quarterly Distribution
per Unit After Reset
  Common
Units Issued
as a Result of the Reset
  2% General
Partner
Interest
  Incentive
Distribution
Rights
  Total   Total
Distributions
 
 
  (dollars in thousands, except per unit amounts)
 

Minimum Quarterly Distribution

                 $0.6500   $ 15,975   $ 2,084   $ 369       $ 2,453   $ 18,428  

First Target Distribution

             $0.6500   up to $0.7475                                      

Second Target Distribution

  above $0.7475   up to $0.8125                                      

Third Target Distribution

  above $0.8125   up to $0.9750                                      

Thereafter

      above $0.9750                                      
                                   

          $ 15,975   $ 2,084   $ 369       $ 2,453   $ 18,428  
                                     

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


Distributions from Capital Surplus

    How Distributions from Capital Surplus Will Be Made

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

    first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price in this offering;

    second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

    thereafter, as if they were from operating surplus.

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

    Effect of a Distribution from Capital Surplus

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

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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;

    the number of common units into which a subordinated unit is convertible;

    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 convertible into two common units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

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


Distributions of Cash Upon Liquidation

    General

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

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

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

    Manner of Adjustments for Gain

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

    first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

    second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

    third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

    fourth, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98.0% to the unitholders, pro rata, and 2.0% to our general partner, for each quarter of our existence;

    fifth, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to our general partner for each quarter of our existence;

    sixth, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75.0% to the unitholders, pro rata, and 25.0% to our general partner for each quarter of our existence;

    thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

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

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        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 AND PRO FORMA FINANCIAL AND OPERATING DATA

        The following table presents as of the dates and for the periods indicated our selected historical and pro forma consolidated financial and operating data, as well as the selected historical combined financial and operating data of our Predecessor.

        The selected historical combined financial data for the period from January 1, 2009 to July 31, 2009 is derived from the audited historical combined financial statements of our Predecessor included elsewhere in this prospectus. The selected historical combined balance sheet data as of July 31, 2009 is derived from the unaudited historical combined financial statements of our Predecessor that are not included in this prospectus. The selected historical consolidated balance sheet data presented as of December 31, 2009 of Southcross Energy LLC is derived from the audited historical consolidated financial statements of Southcross Energy LLC that are not included in this prospectus. The selected historical consolidated financial data presented as of December 31, 2010 and December 31, 2011 and for the period from June 2, 2009 (date of inception) to December 31, 2009 and for the years ended December 31, 2010 and December 31, 2011 have been derived from the audited historical consolidated financial statements of Southcross Energy LLC included elsewhere in this prospectus. The selected historical consolidated financial data presented as of June 30, 2012 and for the six months ended June 30, 2011 and June 30, 2012 are derived from our unaudited historical condensed financial statements included elsewhere in this prospectus. We acquired our initial assets from Crosstex effective as of August 1, 2009. During the period from our inception on June 2, 2009 to July 31, 2009, we had no operations although we incurred certain fees and expenses of approximately $3.0 million associated with our formation and the acquisition of our initial assets from Crosstex, which are reflected in the "Transaction costs" line item of our selected historical consolidated financial data for the period from June 2, 2009 (date of inception) to December 31, 2009.

        The selected pro forma consolidated financial data for the six months ended June 30, 2012 and for the year ended December 31, 2011 have been derived from our unaudited pro forma consolidated financial statements included elsewhere in this prospectus. The selected pro forma consolidated statement of operations for the year ended December 31, 2011 includes the pro forma effects of the EAI acquisition and the pro forma effects of the recapitalization transactions described under "Summary—Recapitalization Transactions and Partnership Structure" as if the EAI acquisition and the recapitalization transactions occurred as of January 1, 2011. The selected pro forma consolidated statement of operations for the six months ended June 30, 2012 presents the pro forma effects of the recapitalization transactions as if they occurred as of January 1, 2011.

        For a detailed discussion of 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 Southcross Energy LLC and our Predecessor's audited combined financial statements and related notes included elsewhere in this prospectus. Among other things, those historical financial

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statements include more detailed information regarding the basis of presentation for the information below.

 
  Southcross Energy
Predecessor
   
   
   
   
   
   
   
  Pro Forma
Southcross
Energy Partners, L.P.
 
 
   
  Southcross Energy LLC    
 
 
   
   
 
 
   
   
  Period from
June 2, 2009 to
December 31,

  Year Ended
December 31,
   
   
   
   
   
 
 
  Period from
January 1, 2009 to

   
  Six Months Ended June 30,    
   
  Six Months
Ended
June 30,
2012
 
 
   
   
  Year Ended
December 31,
2011
 
 
  July 31, 2009    
  2009   2010   2011(3)   2011   2012    
 
 
  (in thousands, except for volume and price amounts)
   
 

Statement of Operations Data:

                                                         

Total Revenue

  $ 330,870       $ 206,634   $ 498,747   $ 523,149   $ 247,489   $ 226,319       $ 548,152   $ 226,319  

Expenses:

                                                         

Cost of natural gas and liquids sold

    301,368         179,045     439,431     460,580     217,125     186,204         479,376     186,204  

Operations and maintenance

    10,648         7,847     21,106     24,707     10,293     15,579         28,701     15,579  

Depreciation and amortization

    7,268         4,235     10,987     12,345     5,602     7,338         13,200     7,338  

General and administrative

    9,788         3,225     7,341     8,926     4,227     5,636         9,312     5,636  

Transaction costs

            2,957     149     203                 203      
                                           

Total expenses

    329,072         197,309     479,014     506,761     237,247     214,757         530,792     214,757  
                                           

Income from operations

    1,798         9,325     19,733     16,388     10,242     11,562         17,360     11,562  

Interest income

            9     25     24     15     4         24     4  

Loss on extinguishment of debt

                    (3,240 )   (3,240 )           (3,240 )    

Interest expense

            (4,554 )   (10,038 )   (5,372 )   (2,817 )   (3,135 )       (6,407 )   (1,726 )

Income tax expense

    (77 )       (372 )   (1 )   (261 )   (166 )   (256 )       (261 )   (256 )
                                           

Net income

  $ 1,721       $ 4,408   $ 9,719   $ 7,539   $ 4,034   $ 8,175       $ 7,476   $ 9,584  
                                           

Statement of Cash Flows Data:

                                                         

Net cash provided by (used in):

                                                         

Operating activities

  $ 4,955       $ 10,164   $ 25,493   $ 20,007   $ 10,402   $ 12,244                  

Investing activities

    (791 )       (238,339 )   (5,231 )   (144,602 )   (37,174 )   (71,603 )                

Financing activities

    (4,164 )       233,899     (5,663 )   105,684     47,545     61,241                  

Balance Sheet Data (at period end):

                                                         

Cash and cash equivalents

  $       $ 5,724   $ 20,323   $ 1,412   $ 41,096   $ 3,294                  

Trade accounts receivable

    50,707         39,956     35,059     41,234     33,696     30,462                  

Property, plant, and equipment, net

    111,645         235,065     229,309     369,861     275,120     448,367                  

Total assets

    167,503         287,808     289,643     420,385     353,543     492,469                  

Total debt (current and long term)

            119,949     115,000     208,280     150,125     214,535                  

Other Financial Data:

                                                         

Adjusted EBITDA(1)

  $ 9,236       $ 16,517   $ 30,869   $ 28,936   $ 12,604   $ 19,046       $ 30,763   $ 19,046  

Gross operating margin(2)

    29,502         27,589     59,316     62,569     30,364     40,115         68,776     40,115  

Maintenance capital expenditures

    565         3,025     3,402     5,317     1,728     1,736         5,423     1,736  

Expansion capital expenditures

    250         1,669     1,843     150,669     49,685     84,080         150,669     84,080  

Operating data:

                                                         

Average throughput of gas (MMBtu/d)

    592,243         492,350     471,265     506,975     446,271     576,404