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TABLE OF CONTENTS
Item 8. Financial Statements and Supplementary Data
PART IV

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


FORM 10-K

ý   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012

OR

o
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                                to                               

Commission file number: 001-35719

Southcross Energy Partners, L.P.
(Exact name of registrant as specified in its charter)

DELAWARE
(State or other jurisdiction of
incorporation or organization)		   45-5045230
(I.R.S. Employer Identification No.)

1700 Pacific Avenue, Suite 2900
Dallas, TX
(Address of principal executive offices)
 
75201
(Zip Code)

(214) 979-3700
www.southcrossenergy.com
(Registrant's telephone number, including area code)

         Securities registered pursuant to Section 12(b) of the Act:

Title of each class   Name of each exchange on which registered
Common Units of Limited Partner Interests   New York Stock Exchange

         Securities registered pursuant to Section 12(g) of the Act: None

         Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o    No ý

         Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o  No ý

         Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

         Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý    No o

         Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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

         Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o    No ý

         As of June 30, 2012, the last business day of the registrant's most recently completed second fiscal quarter, there was no public market for the registrant's Common Units. The registrant's common units began trading on the New York Stock Exchange ("NYSE") on November 7, 2012.

         As of April 9, 2013, the registrant has 12,219,699 common units outstanding and 12,213,713 subordinated units outstanding. Our common units trade on the NYSE under the symbol "SXE".


DOCUMENTS INCORPORATED BY REFERENCE

None

   

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Explanatory Note

        As generally used in the energy industry and in this Form 10-K, the following terms have the following meanings:

Southcross Energy Partners, L.P. and Southcross Energy LLC:

        Southcross Energy Partners, L.P. (the "Partnership," "Southcross," the "Company" "we," "our," or "us"), which closed its initial public offering ("IPO") on November 7, 2012, is a Delaware limited partnership formed in April 2012. Southcross Energy LLC is a Delaware limited liability company, and the predecessor for accounting purposes (the "Predecessor") of the Partnership. References in this Form 10-K to the Partnership or the Company, when used for periods prior to the IPO, refer to Southcross Energy LLC and its consolidated subsidiaries, unless otherwise specifically noted. References in this Form 10-K to the Partnership or the Company, when used for periods beginning at or following the IPO, refer collectively to the Partnership and its consolidated subsidiaries. This Form 10-K reflects the consolidated assets, liabilities, results of operations and cash flows of Southcross Energy Partners, L.P. beginning November 7, 2012 and Southcross Energy LLC for periods ending prior to November 7, 2012.

        In connection with the closing of the IPO, the following transactions occurred:

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INDEX TO ANNUAL REPORT ON FORM 10-K

For the Year Ended December 31, 2012

PART I

Item 1.

  

Business

  
7

Item 1A.

  

Risk Factors

  
29

Item 1B.

  

Unresolved Staff Comments

  
59

Item 2.

  

Properties

  
59

Item 3.

  

Legal Proceedings

  
59

Item 4.

  

Mine Safety Disclosures

  
59

PART II

Item 5.

  

Market for Registrant's Common Equity, Related Unitholders Matters and Issuer Purchases of Units

  
60

Item 6.

  

Selected Financial Data

  
63

Item 7.

  

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

  
64

Item 7A.

  

Quantitative and Qualitative Disclosures about Market Risk

  
82

Item 8.

  

Financial Statements and Supplementary Data

  
84

Item 9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

  
125

Item 9A.

  

Controls and Procedures

  
125

Item 9B.

  

Other Information

  
125

PART III

Item 10.

  

Directors and Executive Officers and Corporate Governance

  
130

Item 11.

  

Executive Compensation

  
137

Item 12.

  

Security Ownership of Certain Management and Beneficial Owners and Management and Related Unitholder Matters

  
152

Item 13.

  

Certain Relationships and Related Transactions and Director Independence

  
155

Item 14.

  

Principal Accountant Fees and Services

  
158

PART IV

Item 15.

  

Exhibits and Financial Statement Schedules

  
159

 

Signatures

  
162

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FORWARD-LOOKING INFORMATION

        Investors are cautioned that certain statements contained in this Form 10-K as well as in periodic press releases and oral statements made by our management team during our presentations are "forward-looking" statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words "expect," "intend," "plan," "anticipate," "estimate," "believe," "will be," "will continue," "will likely result," and similar expressions, or future conditional verbs such as "may," "will," "should," "would," and "could." In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us or our subsidiaries, are also forward-looking statements. These forward-looking statements involve external risks and uncertainties, including, but not limited to, those described under the section entitled "Risk Factors" included herein.

        Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond the control of our management team. All forward-looking statements in this Form 10-K and subsequent written and oral forward-looking statements attributable to us, or to persons acting on our behalf, are expressly qualified in their entirety by these risks and uncertainties. These risks and uncertainties include, among others:

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        Developments in any of these areas could cause actual results to differ materially from those anticipated or projected; or affect our ability to maintain distribution levels; or access necessary financial markets, or cause a significant reduction in the market price of our common units.

        The foregoing list of risks and uncertainties may not contain all of the risks and uncertainties that could affect us. In addition, in light of these risks and uncertainties, the matters referred to in the forward-looking statements contained in this report may not, in fact, occur. Accordingly, undue reliance should not be placed on these statements. We undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as otherwise required by law.

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PART I

        

Item 1.    Business

        The following discussion of our business provides information regarding our principal gathering, transportation, processing, NGL fractionation and other assets. For a discussion of our results of operations, please read Item 7—"Management's Discussion and Analysis of Financial Condition and Results of Operations" of this report.

General Overview

        Southcross Energy Partners, L.P. (the "Partnership," "Southcross," the "Company," "we," "our" or "us"), which closed its initial public offering ("IPO") on November 7, 2012, is a Delaware limited partnership formed in April 2012. Southcross Energy LLC is a Delaware limited liability company, and the predecessor for accounting purposes (the "Predecessor") of the Partnership. References in this Form 10-K to the Partnership or the Company, when used for periods prior to the IPO, refer to Southcross Energy LLC and its consolidated subsidiaries, unless otherwise specifically noted. References in this Form 10-K to the Partnership or the Company, when used for periods beginning at or following the IPO, refer collectively to the Partnership and its consolidated subsidiaries. This report reflects the consolidated assets, liabilities, results of operations and cash flows of Southcross Energy Partners, L.P. beginning November 7, 2012 and Southcross Energy LLC for periods ending prior to November 7, 2012. Southcross Energy LLC and its subsidiaries are controlled through investment funds and entities associated with Charlesbank Capital Partners, LLC ("Charlesbank").

        The Partnership provides natural gas gathering, processing, treating, compression and transportation services and natural gas liquid ("NGL") fractionation and transportation services for its producer customers. We also source, purchase, transport and sell natural gas and NGLs to power generation, industrial and utility customers. Our assets are located in South Texas, Mississippi and Alabama and, as of December 31, 2012, included three gas processing plants, two NGL fractionation plants and approximately 2,700 miles of pipeline. Our South Texas assets operate in or within close proximity to the Eagle Ford shale region. Our assets are strategically positioned to provide transportation of natural gas and NGLs to power generation, industrial and utility customers as well as to unaffiliated pipelines. The Partnership is a midstream natural gas company and operates as one reportable segment.

Emerging Growth Company Status

        We are an "emerging growth company," as defined in the Jumpstart Our Business Startups Act of 2012, ("JOBS Act"). For as long as we are deemed an emerging growth company, we may take advantage of specified reduced reporting and other regulatory requirements that are generally unavailable to other public companies. These provisions include:

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        We may take advantage of these provisions until we are no longer an emerging growth company, which will occur on the earliest of:

        We have elected to adopt the reduced disclosure requirements described above, except that 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.

Initial Public Offering

        On November 7, 2012, we completed our IPO. After the completion of the IPO and the full exercise of the underwriters' over-allotment option to purchase additional common units, Southcross Energy LLC owns, on behalf of its members, the equity interests in Southcross Energy Partners GP, LLC, our general partner ("General Partner"), as well as common and subordinated units of the Partnership. Southcross Energy LLC's total direct and indirect equity ownership in the Partnership as of December 31, 2012 was 58.5%. Our common units are listed on the New York Stock Exchange ("NYSE") and are traded under the symbol "SXE."

Ownership Structure

        The following table depicts our ownership structure as of December 31, 2012:

Description
  Percentage
ownership 		 

Public common units

     41.5 %

Southcross Energy LLC:

        

Common units

     7.5 %

Subordinated units

     49.0 %

General partner interest(1)

     2.0 %
       

Total

    100.0 %
       
(1)
General partner interest is owned by Southcross Energy Partners GP, LLC which is 100% owned by Southcross Energy LLC.

Recent Events

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Business Strategy

        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:

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Competitive Strengths

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

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Our Operations

        Our assets consist of gathering systems, intrastate pipelines, three natural gas processing plants, two NGL fractionators, and ancillary assets.

        The following tables provide information regarding our assets as of and for the year ended December 31, 2012:

 
   As of
December 31, 2012 		  Year ended
December 31, 2012 		 
Gathering systems and intrastate pipelines
  Miles   Approximate design
capacity (MMcf/d) 		  Approximate average
throughput (MMcf/d) 		 

South Texas

     1,555     665     338  

Mississippi/Alabama

     1,145     720     207  
               

Total

     2,700     1,385     545  
               

 

 
   As of
December 31, 2012 		  Year ended
December 31, 2012 		 
Processing plants
  Approximate design
capacity (MMcf/d) 		  Approximate average
processing volumes (MMcf/d) 		 

Gregory

     135     87  

Conroe

     50     23  

Woodsboro

     200     3  
           

Total

     385     113  
           

 

 
   As of
December 31, 2012 		  Year ended
December 31, 2012 		 
Fractionation plants
  Fractionation
capacity (Bbls/d) 		  Average
output (Bbls/d) 		 

Gregory

     4,800     3,745  

Bonnie View

     11,500     416  
           

Total

     16,300     4,161  
           

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        We derive revenue primarily from fixed-fee and fixed-spread arrangements. For the year ended December 31, 2012, our fixed-fee and fixed-spread arrangements accounted for approximately 93% of our gross operating margin. Our contracts vary in duration from one month to ten years and the duration and pricing of our contracts vary depending upon several factors, including our competitive position, our acceptance of risks associated with longer-term contracts, and our desire to recoup over the term of a contract any capital expenditures that we are required to incur in order to provide service to our customers.

        We continually seek new sources of natural gas supply and power generation, industrial and utility markets to increase the gas throughput volume on our gathering and pipeline systems and through our processing plants.

South Texas

        The assets in our South Texas region are located between Houston and Freer, a city that is located approximately 50 miles west of Corpus Christi, Texas. As of December 31, 2012, these assets consisted of approximately 1,555 miles of pipeline ranging in diameter from 2 to 20 inches, our Woodsboro processing plant, our Bonnie View NGL fractionation plant, our Gregory processing plant and NGL fractionation plant, and our Conroe gathering system and its associated processing plant.

        The majority of our pipelines in South Texas feed rich gas from multiple producing fields, including the Eagle Ford Shale, to our processing and NGL fractionation facilities at Woodsboro, Gregory and Conroe. The residue gas pipelines from our processing plants and the remaining pipelines

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in lean gas service in South Texas are used to serve multiple industrial and electric generation customers, and to deliver gas to a number of intrastate and interstate pipelines.

GRAPHIC

        In 2012, we started our Woodsboro processing plant, a 200 MMcf/d cryogenic processing plant located in Refugio County, Texas, that significantly expanded our South Texas processing capacity and, along with our new Bonnie View NGL fractionation plant, considerably increased our NGL production capabilities.

        In February 2013, we completed construction of our Bee Line pipeline, a 57 mile pipeline that added 320 MMcf/d of capacity to our system in order to move rich gas from the central Eagle Ford Shale area in Dewitt and Karnes counties to our Woodsboro processing plant.

        Prior to startup of our Woodsboro processing plant, the majority of our customers' gas in South Texas had been delivered to third-party processing plants, including the Formosa processing plant located in Point Comfort, Texas and the Hilcorp processing plant located in Old Ocean, Texas. Our agreement with Formosa is in effect through May 31, 2013. The volumes of our gas covered by the agreement gradually decrease between January 2013 and the agreement termination date, after which all of our rich gas will be routed to our Woodsboro processing plant, our Gregory processing plant, and, if necessary, to other third party processing plants.

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        Our Gregory processing plant is a cryogenic natural gas plant comprised of two units collectively having a total capacity of 135 MMcf/d. This plant processes natural gas from both a local gathering system and from sources elsewhere on our South Texas pipeline systems. NGLs produced at our Gregory processing plant are fractionated in our NGL fractionator located on the same site. The Gregory NGL fractionation plant has a total capacity of 4,800 Bbls/d.

        We increased our NGL fractionation capacity via the completion of our new Bonnie View NGL fractionation plant. The plant began operations in the fourth quarter of 2012 and expanded its capacity to 22,500 Bbls/d in February 2013.

        Purity ethane from our Gregory and Bonnie View plants is shipped via pipeline to a subsidiary of The Dow Chemical Company while remaining NGLs are shipped via pipeline or trucked to local markets.

        In January 2013, we performed significant turnaround maintenance at our Gregory processing and NGL fractionation plants to increase their reliability and to increase NGL recoveries at the facility. We believe these enhancements will increase profitability and allow us to be more competitive in securing future gas supplies. As the turnaround maintenance was nearing completion, on January 26, 2013, we experienced a fire at the facility. Damage was limited to a small portion of the facility and we completed repairs and resumed operations during April 2013. We maintain property insurance which is expected to cover most of the repair costs related to the damage caused by the fire, less our $250,000 deductible. We also maintain business interruption insurance, which is effective after a 30-day waiting period subsequent to an event of loss. While there will be some financial impact in the first quarter of 2013 due to reduced operations at our Gregory facility, we do not foresee a material or lasting operational or financial impact from the fire.

        Our Conroe processing plant and gathering system operate together on a stand-alone basis north of Houston in Montgomery County, Texas to gather, process, sell and recycle natural gas. The processing plant is a 50 MMcf/d cryogenic natural gas plant. We have fixed-fee processing contracts with producers, under which the majority of the residue gas from the Conroe plant is returned to the producers for gas lift purposes. We sell the remaining residue gas and NGLs to unaffiliated parties.

Mississippi and Alabama

        The assets in our Mississippi region are located principally in the southern half of the state and comprise the largest intrastate pipeline system in Mississippi. The Mississippi assets consist of 626 miles of pipeline ranging in diameter from 2 to 20 inches with an estimated design capacity of 345 MMcf/d and two treating plants. Our system throughput volumes in Mississippi are affected by both on-system gas production volumes and customers' demand for gas. The system has the capability to receive natural gas from three unaffiliated interstate pipelines—Southeast Supply Header, Southern Natural

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Gas Company (SONAT) and Texas Eastern—to supplement supply on the system or to market gas off the system.

GRAPHIC

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        The assets in our Alabama region are located in northwest and central Alabama and consist of 519 miles of natural gas gathering pipeline ranging from 2 to 16 inches in diameter with an estimated design capacity of 375 MMcf/d. The primary gas supply to the system is coal bed methane gas from the Black Warrior Basin with incremental volumes gathered from conventional gas wells.

GRAPHIC

Competition

        The natural gas gathering, compression, processing, transportation and marketing business and the NGL fractionation business are highly competitive. Our competitors include other midstream companies, producers and intrastate and interstate pipelines. Competition for natural gas volumes is based primarily on commercial terms, reliability, service levels, flexibility, access to markets, location, available capacity, connection costs and fuel efficiencies. Our principal competitors are Copano Energy, L.L.C., DCP Midstream LLC, Energy Transfer Partners, L.P., Enterprise Products Partners LP, Gulf South Pipeline Company, LP, Kinder Morgan Energy Partners LP, Southeast Supply Header, LLC and Teak Midstream LLC.

        In addition to competing for natural gas supply volumes, we face competition for customer markets, which is based primarily on the proximity of pipelines to the markets, price and assurance of supply.

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Customers and Concentration of Credit Risk

        The Partnership's markets are in Texas, Alabama and Mississippi and we have a concentration of trade accounts receivable due from customers engaged in the purchase and sale of natural gas and NGL products, and other services. These concentrations of customers may affect our overall credit risk as these customers may be similarly affected by changes in economic, regulatory or other factors. The Partnership analyzes customers' historical financial and operational information prior to extending credit and monitors creditworthiness on a periodic basis.

        Formosa and Sherwin Alumina Company ("Sherwin") were significant customers of the Partnership in 2012. Revenues from Formosa and Sherwin were $120.4 million or 24.3% and $54.5 million or 11.0%, respectively, for the year ended December 31, 2012. Curtailments and other actions by Formosa impacted our operations and results in 2012. Our agreement with Formosa expires on May 31, 2013.

Governmental Regulation

        We are subject to regulation by the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration (the "PHMSA") pursuant to the Natural Gas Pipeline Safety Act of 1968 (the "NGPSA"), and the Pipeline Safety Improvement Act of 2002 (the "PSIA"), which was reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (the "PIPESA"). The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transmission pipelines in high-consequence areas. The PHMSA has developed regulations implementing the PSIA that require transportation pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in "high consequence areas," such as high population areas. 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 PHMSA issued advance notices of proposed rulemaking on a range of topics relating to the safety of gas and NGL pipelines, among other pipelines. The advance notices of proposed rulemaking requested comment on a number of topics, including whether to extend regulation to certain pipelines currently exempt from federal safety regulations and whether to extend integrity management regulations to additional pipelines. The PHMSA has not yet taken further action on the issues raised in the advance notices of proposed rulemaking. The PHMSA also recently published an advisory bulletin providing guidance on verification of records related to pipeline maximum allowable operating pressure. Although we have reviewed our records in regard to such matters, no final determination has yet been made as to whether our records will meet those requirements. Additionally, the National Transportation Safety Board has recently recommended that the PHMSA make a number of changes to its rules, including removing an exemption from most safety inspections for natural gas pipelines installed before 1970.

        While we cannot predict the outcome of proposed legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our operations, particularly by extending more stringent and comprehensive safety regulations (such as integrity management requirements) to pipelines and gathering lines not previously subject to such requirements. Further legislative and regulatory changes may also result in higher penalties for the violation of federal pipeline safety regulations. While we expect any legislative or regulatory changes to allow us time to become compliant with new requirements, costs associated with compliance may have a material effect on our operations. We cannot predict with any certainty at this time the terms of any new laws or rules

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or the costs of compliance associated with such requirements, but we regularly inspect our pipelines and third parties assist us in interpreting the results of the inspections.

        States are largely preempted by federal law from regulating pipeline safety for interstate lines but most states are certified by the U.S. Department of Transportation (the "DOT") to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include requirements for facility design and management in addition to requirements for pipelines. We do not anticipate any significant difficulty in complying with applicable state laws and regulations. Our natural gas and natural gas products pipelines have continuous inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.

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

        We and the entities in which we own an interest are also subject to:

Regulation of Operations

        Regulation of pipeline gathering and transportation services, natural gas sales and transportation of NGLs may affect certain aspects of our business and the market for our products and services.

Intrastate Pipelines

        Our transmission lines are subject to state regulation of rates and terms of service. In Texas, the regulatory system allows rates to be negotiated on a customer-by-customer basis and are subject to a complaint-based review process. In rare circumstances, as allowed by statute, regulators may initiate a rate review. Although Texas does not have an "open access" requirement, there is a

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"non-discriminatory access" requirement, which is subject to a complaint-based review. In Mississippi and Alabama, the regulatory systems allow special contracts that are negotiated on a customer-by-customer basis for approval by the applicable state commission.

Section 311 Pipelines

        Intrastate transportation of natural gas is largely regulated by the state in which such transportation takes place. Several of our intrastate pipeline subsidiaries, Southcross CCNG Transmission Ltd., Southcross Gulf Coast Transmission Ltd., Southcross Mississippi Pipeline, L.P. and Southcross Alabama Pipeline LLC, also provide interstate transportation services. The rates, terms and conditions of such services are subject to the Federal Energy Regulatory Commission (the "FERC") jurisdiction under Section 311 of the Natural Gas Policy Act, ("NGPA"), and Part 284 of the FERC's regulations. Pipelines providing transportation service under Section 311 are required to provide services on an open and nondiscriminatory basis. The NGPA regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of an interstate natural gas pipeline or a local distribution company or LDC served by an interstate natural gas pipeline. Under Section 311, rates charged for intrastate transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The rates under Section 311 approved by the FERC are maximum rates and we may negotiate at or below such rates. Currently, the FERC reviews our maximum rates every five years and such maximum rates may increase or decrease as a result of such reviews. At this time, the next rate review will be February 1, 2014. The terms and conditions of service set forth in the intrastate pipeline's statement of operating conditions are also subject to the FERC's review and approval. Should the FERC determine not to authorize rates equal to or greater than our currently approved Section 311 rates, our business may be adversely affected. Failure to observe the service limitations applicable to transportation and storage services under Section 311, failure to comply with the rates approved by the FERC for Section 311 service, and/or failure to comply with the terms and conditions of service established in the pipeline's FERC-approved statement of operating conditions could result in alteration of jurisdictional status, and/or the imposition of administrative, civil and criminal remedies or sanctions.

Hinshaw Pipelines

        Similar to intrastate pipelines, Hinshaw pipelines, by definition, also operate within a single state. We have a Mississippi pipeline segment which is categorized as a Hinshaw pipeline. Also, similar to pipelines operating under Section 311 of the NGPA, Hinshaw pipelines can receive gas from outside their state without becoming subject to FERC's NGA jurisdiction. Specifically, Section 1(c) of the NGA exempts from the FERC's NGA jurisdiction those pipelines that transport gas in interstate commerce if (1) they receive natural gas at or within the boundary of a state, (2) all the gas is consumed within that state and (3) the pipeline is regulated by a state commission. Following the enactment of the NGPA, the FERC issued Order No. 63 authorizing Hinshaw pipelines to apply for authorization to transport natural gas in interstate commerce in the same manner as intrastate pipelines operating pursuant to Section 311 of the NGPA. Hinshaw pipelines frequently operate pursuant to blanket certificates to provide transportation and sales service under the FERC's regulations.

        Historically, the FERC did not require intrastate and Hinshaw pipelines to meet the same rigorous transactional reporting guidelines as interstate pipelines. However, as discussed below, in 2010, the FERC issued a new rule, Order No. 735, which increases FERC regulation of certain intrastate and Hinshaw pipelines. See "—Market Behavior Rules; Reporting Requirements."

Gathering Pipeline Regulation

        Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC. We believe that our natural gas pipelines meet the traditional tests that the FERC has used to

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determine that a pipeline is a gathering pipeline and is, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities are subject to change based on future determinations by the FERC, the courts or U.S. 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 such companies transferring gathering facilities to 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. Our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services. Our natural gas gathering operations also may be or become subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

        Our natural gas gathering operations are subject to ratable take and common purchaser statutes in most of the states in which we operate. These statutes generally require our gathering pipelines to take natural gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. The states in which we operate have adopted a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. To date, there have been no adverse effects to our systems due to these regulations.

Market Behavior Rules; Reporting Requirements

        On August 8, 2005, Congress enacted the Energy Policy Act of 2005, ("the EPAct 2005"). Among other matters, the EPAct 2005 amended the NGA to add an anti-manipulation provision that makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by the FERC and, furthermore, provides the FERC with additional civil penalty authority. On January 19, 2006, the FERC, issued Order No. 670, a rule implementing the anti-manipulation provision of the EPAct 2005, and subsequently denied rehearing. The rules make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC or the purchase or sale of transportation services subject to the jurisdiction of the FERC to (1) use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-manipulation rules apply to interstate gas pipelines and storage companies and intrastate gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted "in connection with" gas sales, purchases or transportation subject to FERC jurisdiction. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but only to the extent such transactions do not have a "nexus" to

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jurisdictional transactions. The EPAct 2005 also amends the NGA and the NGPA to give the FERC authority to impose civil penalties for violations of these statutes, up to $1,000,000 per day per violation for violations occurring after August 8, 2005. In connection with this enhanced civil penalty authority, the FERC issued a policy statement on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. Should we fail to comply with all applicable FERC-administered statutes, rule, regulations and orders, we could be subject to substantial penalties and fines.

        The EPAct 2005 also added a Section 23 to the NGA authorizing the FERC to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce. In 2007, the FERC took steps to enhance its market oversight and monitoring of the natural gas industry by issuing several rulemaking orders designed to promote gas price transparency and to prevent market manipulation. In December 2007, the FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Order No. 704 requires buyers and sellers of annual quantities of natural gas of 2,200,000 MMBtu or more, including entities not otherwise subject to the FERC's jurisdiction, to provide by May 1 of each year an annual report to the FERC describing their aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with the FERC's policy statement on price reporting. In June 2010, the FERC issued the last of its three orders on rehearing and clarification further clarifying its requirements.

        In May 2010, the FERC issued Order No. 735, which requires intrastate pipelines providing transportation services under Section 311 of the NGPA and Hinshaw pipelines operating under Section 1(c) of the NGA to report on a quarterly basis more detailed transportation and storage transaction information, including: rates charged by the pipeline under each contract; receipt and delivery points and zones or segments covered by each contract; the quantity of natural gas the shipper is entitled to transport, store, or deliver; the duration of the contract; and whether there is an affiliate relationship between the pipeline and the shipper. Order No. 735 further requires that such information must be supplied through a new electronic reporting system and will be posted on the FERC's website, and that such quarterly reports may not contain information redacted as privileged. The FERC promulgated this rule after determining that such transactional information would help shippers make more informed purchasing decisions and would improve the ability of both shippers and the FERC to monitor actual transactions for evidence of market power or undue discrimination. Order No. 735 also extends the Commission's periodic review of the rates charged by the subject pipelines from three years to five years. Order No. 735 became effective on April 1, 2011.

        In October 2010, the FERC issued a Notice of Inquiry seeking public comment on the issue of whether and how parties that hold firm capacity on some intrastate pipelines can allow others to use their capacity, including to what extent buy/sell transactions should be permitted and whether the FERC should consider requiring such pipelines to offer capacity release programs. In the Notice of Inquiry, the FERC granted a blanket waiver regarding such transactions while the FERC is considering these policy issues. The comment period has ended but the FERC has not yet issued an order.

State Utility Regulation

        Some of our operations in Texas are specifically subject to the Texas Gas Utility Regulatory Act, as implemented by the Railroad Commission of Texas ("RRC"). Generally, the RRC has authority to ensure that rates charged for natural gas sales or transportation services are just and reasonable. Our gas utilities, Southcross CCNG Gathering Ltd., Southcross CCNG Transmission Ltd. and Southcross

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Gulf Coast Transmission Ltd., are required to file gas tariffs and Southcross NGL Pipeline, L.P. has filed a NGL tariff with the RRC.

        In Mississippi, the Mississippi Public Service Commission ("MPSC") considers Southcross Mississippi Industrial Gas Sales, L.P. ("MIGS") a utility and it is necessary to get contract approval for the negotiated contract. MIGS is a transporter to an end-user, the Leaf River Cellulose Plant, which is located within Mississippi.

        In Alabama, the Alabama Public Service Commission ("APSC") requires a gas utility to file "special negotiated contracts" with the APSC for approval. The requirement includes our Southcross Alabama Gathering System, L.P. and Southcross Alabama Pipeline LLC.

        Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Sales of Natural Gas and NGLs

        Historically, the transportation and sale or resale of natural gas in interstate commerce has been regulated by the FERC under the NGA, the NGPA and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

        The price at which we sell natural gas is currently not subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

        Sales of NGLs are currently not regulated and are made at negotiated prices. Nevertheless, Congress could enact price controls in the future.

        As discussed above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting interstate natural gas pipelines and those initiatives may also affect the intrastate transportation of natural gas both directly and indirectly.

Anti-terrorism Measures

        The Department of Homeland Security Appropriation Act of 2007 requires the Department of Homeland Security (the "DHS") to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present "high levels of security risk." The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to this act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. Covered facilities that are determined by DHS to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements, including those regarding inspections, audits, recordkeeping and protection of chemical-terrorism vulnerability information. Three of our facilities (the Gregory, Conroe and Woodsboro plants)

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have more than the threshold quantity of listed chemicals; therefore, a "Top Screen" evaluation was submitted to the DHS. The DHS reviewed this information and determined that none of the facilities are considered high-risk chemical facilities.

Cyber Security Measures

        While we are currently not subject to governmental standards for the protection of computer-based systems and technology from cyber threats and attacks, proposals to establish such standards are being considered in the U.S. Congress and by U.S. Executive Branch departments and agencies, including the Department of Homeland Security, and we may become subject to such standards in the future. Currently, we are implementing our own cyber security programs and protocols; however, we cannot guarantee their effectiveness. A significant cyber-attack could have a material effect on operations and those of our customers.

Environmental Matters

General

        Our operation of pipelines, plants and other facilities for natural gas gathering, processing, treating, compression and transportation, and for NGL fractionation and transportation services are subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

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

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

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participate in industry groups that help formulate recommendations for addressing existing or future regulations.

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

Hazardous Substances and Waste

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

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

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

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Oil Pollution Act

        In 1991, the EPA adopted regulations under the Oil Pollution Act (the "OPA"). These oil pollution prevention regulations, as amended several times since their original adoption, require the preparation of a Spill Prevention Control and Countermeasure Plan ("SPCC") for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the U.S. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility's operations comply with the requirements. To be in compliance, the facility's SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacility piping), inspections and records, security, and training. Most importantly, the facility must fully implement the SPCC plan and train personnel in its execution. We believe that none of our facilities is materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

Air Emissions

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

        On August 20, 2010, the EPA published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocating internal combustion engines. On May 22, 2012, the EPA proposed amendments to the final rule in response to several petitions for reconsideration. The EPA finalized the proposed amendments on January 14, 2013. With the passed amendment, the impacts of this rule will likely not have any material financial impact on our operations. The rule will require us to undertake certain activities, including following prescribed maintenance practices for engines (which are consistent with our existing practices). Compliance with the final rule currently is required by October 2013.

        On June 28, 2011, the EPA issued a final rule, effective August 29, 2011, modifying existing regulations under the CAA that established new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The final rule may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment. Compliance with the final rule is not required until at least 2013. On January 14, 2013, the EPA issued minor amendments to the rule. We are currently evaluating the impact that this final rule and proposed amendments will have on our operations.

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        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. For new or reworked hydraulically-fractured gas wells, the final rule requires controlling emissions through flaring until 2015, when the rule requires the use of reduced emission, or "green", completions. 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 business.

Water Discharges

        The Federal Water Pollution Control Act (the "Clean Water Act"), and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the U.S. and impose requirements affecting our ability to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. We believe that compliance with existing permits and compliance with foreseeable new permit requirements under the Clean Water Act and state counterparts will not have a material adverse effect on our financial condition, results of operations or cash flow.

Safe Drinking Water Act

        The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. We believe that our facilities will not be materially adversely affected by such requirements.

Endangered Species

        The Endangered Species Act (the "ESA") restricts activities that may affect endangered or threatened species or their habitats. While some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans or limit future development activity in the affected areas.

National Environmental Policy Act

        The National Environmental Policy Act, (the "NEPA"), establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process

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for implementing these goals within federal agencies. A major federal agency action having the potential to impact significantly the environment requires review under NEPA and, as a result, many activities requiring FERC approval must undergo NEPA review. Many of our activities are covered under categorical exclusions which results in a shorter NEPA review process. The Council on Environmental Quality has announced an intention to reinvigorate NEPA reviews and, on March 12, 2012, issued final guidance that may result in longer review processes that could lead to delays and increased costs that could materially adversely affect our revenues and results of operations.

Climate Change

        Recent scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases" or "GHG" and including carbon dioxide and methane, may be contributing to warming of the Earth's atmosphere. In response to the scientific studies, international negotiations to address climate change have occurred. The United Nations Framework Convention on Climate Change, also known as the "Kyoto Protocol," became effective on February 16, 2005 as a result of these negotiations, but the U.S. did not ratify the Kyoto Protocol. At the end of 2009, an international conference to develop a successor to the Kyoto Protocol issued a document known as the Copenhagen Accord. Pursuant to the Copenhagen Accord, the U.S. submitted a greenhouse gas emission reduction target of 17 percent by 2020 compared to 2005 levels. We continue to monitor the international efforts to address climate change. Their effect on our operations cannot be determined with any certainty at this time.

        In the U.S., legislative and regulatory initiatives are underway to limit GHG emissions. The U.S. Congress has considered legislation that would control GHG emissions through a "cap and trade" program and several states have already implemented programs to reduce GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the federal CAA definition of an "air pollutant," and in response the EPA promulgated an endangerment finding paving the way for regulation of GHG emissions under the CAA. In 2010, the EPA issued a final rule, known as the "Tailoring Rule," that makes certain large stationary sources and modification projects subject to permitting requirements for greenhouse gas emissions under the Clean Air Act.

        In addition, 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. 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. We submitted timely the reports required under this rule and have adopted procedures for future required reporting.

        Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. Moreover, while the U.S. Supreme Court held in its June 2011 decision in American Electric Power Co., Inc. v. Connecticut that with respect to claims concerning GHG emissions, the federal common law of nuisance was displaced by the federal Clean Air Act, the Court left open the question whether tort claims against GHG emissions sources alleging property damage may proceed under state common law. There thus remains some litigation risk for such claims. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on us.

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        Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher greenhouse gas emitting energy sources, our products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. To the extent that our products are competing with lower greenhouse gas emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on greenhouse gas emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.

        The majority of scientific studies on climate change suggest that stronger storms may occur in the future in the areas where we operate, although the scientific studies are not unanimous. Due to their location, our operations along the Gulf Coast are vulnerable to operational and structural damages resulting from hurricanes and other severe weather systems and our insurance may not cover all associated losses. We are taking steps to mitigate physical risks from storms, but no assurance can be given that future storms will not have a material adverse effect on our business.

Employees

        As a result of the IPO transactions and the conveyance of Southcross Energy LLC's subsidiaries, we had 156 employees who provided direct, full-time support to our operations during the transition period from November 7, 2012 to December 31, 2012. On January 1, 2013, all employees were transferred to our General Partner. None of these employees are covered by collective bargaining agreements, and our General Partner considers its employee relations to be good. Currently, we do not have any employees. The officers of our General Partner manage our operations and activities and oversee its 156 employees.

Available Information and Corporate Governance Documents

Available Information

        We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to such reports, as well as other documents electronically with the U.S Securities and Exchange Commission ("SEC") under the Securities Exchange Act of 1934, as amended ("Exchange Act"). From time-to-time, we also may file registration and related statements pertaining to equity or debt offerings. We provide access free of charge to all of these materials, as soon as reasonably practicable after such materials are filed with, or furnished to the SEC, on our Internet site located at www.southcrossenergy.com.

        The public may obtain such reports from the SEC's Internet website at www.sec.gov. The public may also read and copy any materials that we file with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Room 1580, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1 (800) SEC-0330.

Corporate Governance Documents

        Our Corporate Governance Guidelines, Code of Business Conduct and Ethics and the charters of the audit committee and the compensation committee of our General Partner's board of directors also are available on our Internet website. Also we will provide, free of charge, a copy of any of our governance documents listed above upon written request to our General Partner's corporate secretary at our principal executive office. Our principal executive offices are located at 1700 Pacific Avenue, Suite 2900, Dallas, Texas 75201 and our telephone number is 1 (214) 979-3700.

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Item 1A.    Risk Factors

        You should carefully consider the following risk factors, together with all of the other information included in this report, when deciding whether to invest in us. Limited partner interests 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 a similar business. You should be aware that the occurrence of any of the events described in this report could have a material adverse effect on our business, financial condition, results of operations and cash flows. In such event, we may be unable to make distributions to our unitholders and the trading price of our common units could decline.

Risks Related to Our Business

        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:

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

        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 also will 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:

        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, oil or NGL prices decrease. Declines in natural gas, oil or NGL prices could have a negative impact on exploration, development and production activity, and sustained low prices 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.

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        Because of these and other factors, even if natural gas and liquid 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 obtain independent evaluations of the natural gas reserves connected to our systems on a regular or ongoing basis. Accordingly, we do 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.

        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.

        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.

        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:

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        We currently generate a large portion of our revenues pursuant to fixed-fee 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, this portion of our existing operations and cash flows have limited direct exposure to commodity price levels. 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 successful. We may acquire or develop additional midstream assets or change the arrangements under which we process our volumes. These changes may also impact our transportation and gathering costs 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 and our ability to make distributions.

        In addition, another large portion of our revenues is generated pursuant to fixed-spread contracts under which we strive to buy and sell equal volumes of natural gas and NGLs at prices based upon the same index price of the commodity. Our ability to do this is based upon a number of factors, including willingness of customers to accept the same index as a basis, physical differences in geography, product specifications, and ability to market products at the anticipated differential from the pricing index.

        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 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 commodity-sensitive 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 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. 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 a similar volume of natural gas at delivery points on our systems, we may not

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be able to mitigate all exposure to commodity price risks. 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. To the extent that we are exposed to intra-month commodity price fluctuations, we enter into monthly swing swaps.

        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 NGL 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 NGL fractionation facilities in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flow could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

        We 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. 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.

        A significant percentage of our revenue is attributable to a relatively limited number of customers. Our top ten customers accounted for 65.5% of our revenue for the year ended December 31, 2012. We have gathering, processing and/or transportation and/or sales contracts with each of these customers of varying duration and commercial terms. If we are 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. 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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        Two customers, Formosa and Sherwin accounted for 24.3% and 11.0%, respectively of our revenue for the year ended December 31, 2012. 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 on May 31, 2013. If we are unable to access Formosa's processing facility prior to May 2013, we expect to have the ability to take the same natural gas volume from our producers and process it at one of our own facilities. If we do not have the ability to process this level of natural gas volume, it may have an adverse effect on our revenue, cash flows and our ability to make cash distributions to our unitholders.

        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 natural disasters 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 operating margin and ability to make cash distributions to our unitholders could be adversely affected.

        Significant portions of our pipeline systems and processing plants have been in service for many decades. Our executive management team 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.

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        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:

        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. 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.

        Our ability to grow is affected, in part, by 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 because our amended Credit Facility restricts us from making acquisitions or (iii) outbid by competitors or for any other reason, then our future growth and ability to increase cash distributions could be limited.

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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:

        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.

        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.

        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.

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        In general, we rely, in large part, on banks and capital markets to fund our operations, contractual commitments and refinance existing debt. These markets can experience high levels of volatility and access to capital can be constrained for an extended period of time. In addition to conditions in the capital markets, a number of other factors could cause us to incur increased borrowing costs and to have greater difficulty accessing public and private markets for both secured and unsecured debt. These factors include our financial performance. If we are unable to secure financing on acceptable terms, our other sources of funds, including available cash, bank facilities, and cash flow from operations may not be adequate to fund our operations, contractual commitments and refinance existing debt.

        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.

        As of December 31, 2012, we had total indebtedness of $191 million. Our future level of debt could have important consequences to us, including the following:

        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.

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        The gathering, processing, treating, compression and transportation of natural gas and NGL fractionation and transportation services require 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.

        We are dependent upon the earnings and cash flow generated by our operations in order to meet our debt service obligations and to make cash distributions to our unitholders. The operating and financial restrictions and covenants in our credit facility and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make cash distributions to our unitholders. Our credit facility limits our ability among other things, to:

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

        The provisions of our 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 credit facility could result in a default or an event of default that could enable our lenders, subject to the terms and conditions of the credit facility, 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.

        For a complete description of long-term debt, see Part II, Item 8, "Financial Statements and Supplementary Data—Notes to the Consolidated Financial Statements—Note 6—Long-Term Debt."

        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

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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 may 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 between 2012 and 2014. 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. 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.

        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.

        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

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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 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.

        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 FERC under the 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.

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        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 and pipeline transportation business. In addition, the classification and regulation of our gathering 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.

        Our natural gas gathering, compression, treating and transportation operations and NGL 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:

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        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 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. 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.

        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:

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        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 pipeline 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 in South Texas. We have incurred costs of approximately $1.8 million during 2012 in order to complete the testing required by existing DOT regulations and their state counterparts. This expenditure included all costs associated with repairs, remediations, preventative and mitigating actions related to the 2012 testing program. 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.

        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. 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

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thereafter. We timely submitted the reports required under this rule and have adopted procedures for future required reporting. 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 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.

        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

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and reduce our cash available for capital expenditures or other partnership purposes. A requirement to post cash collateral could therefore reduce our willingness or ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of swaps as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

        The inability of the legislative and executive branches of the U.S. government to pass a federal government budget, address tax revenue requirements, control deficit spending, and effectively manage short and long-term U.S. government borrowing, debt ratings, and debt ceiling adjustments, could negatively impact U.S. domestic and global financial markets thereby reducing demand by our customers for our services thereby reducing revenues. Similarly, if our suppliers face challenges in obtaining credit, in selling their products, or otherwise in operating their businesses, they may become unable to continue to offer the materials we purchase from them. These actions could result in reductions in our revenues, increased price competition, or increased operating costs, which could adversely affect our business results of operations and financial condition.

        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.

        Our success is dependent upon the efforts of our senior management, as well as on our ability to attract and retain senior management. Our senior executive officers have significant experience in the natural gas industry and have developed strong relationships with a broad range of industry participants. The loss of any of these executives could prevent us from implementing our business strategy and have a material adverse effect on our relationships with these industry participants, our results of operations and ability to make cash distributions to our unitholders.

        We do not have employees. We rely solely on officers and employees of the General Partner to operate and manage our business.

        We are subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, (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

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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 through December 31, 2017.

        We have limited history operating as a publicly traded partnership. As a publicly traded partnership, we are incurring 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. These rules and regulations are increasing 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 are incurring 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.

        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.

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Risks Inherent in an Investment in Us

        Southcross Energy LLC controls our General Partner, and has the authority to appoint all of the officers and directors of our General Partner, some of whom are also officers of Charlesbank, the entity that controls Southcross Energy LLC. 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, Southcross Energy LLC. Conflicts of interest may arise between Southcross Energy LLC 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 Southcross Energy LLC over our interests and the interests of our unitholders. These conflicts include the following situations, among others:

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        Charlesbank is not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. 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 conflicts of interest between us and affiliates of our General Partner and result in less than favorable treatment of us and our unitholders.

        There were 10,350,000 publicly traded common units at December 31, 2012. In addition, affiliates of our General Partner own 1,863,713 common units and 12,213,713 subordinated units. You may not be able to resell your common units at or above your acquisition price. Additionally, a 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.

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        The market price of our common units may decline and be influenced by many factors, some of which are beyond our control, including:

        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.

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

        In addition, because we distribute all of our available cash, we may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our 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.

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        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. As of December 31, 2012, affiliates of our General Partner owned, directly or indirectly, 15.3% of the outstanding common units and all of our outstanding subordinated units.

        Prior to making any distribution on our common units, we will reimburse our General Partner and its affiliates, including Southcross Energy LLC, 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 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.

        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 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:

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        By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above.

        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:

        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

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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.

        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 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 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.

        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 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 Southcross Energy LLC. 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

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operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

        Our unitholders are currently unable to remove our General Partner without its consent because our General Partner and its affiliates own sufficient units 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. As of December 31, 2012, affiliates of our General Partner own 57.6% 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.

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

        Our General Partner 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 Southcross Energy LLC 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.

        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:

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        As of December 31, 2012, Southcross Energy LLC held an aggregate of 1,863,713 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.

        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 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. As of December 31, 2012, Southcross Energy LLC owned approximately 15.3% 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), Southcross Energy LLC will own approximately 57.6% of our outstanding common units.

        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:

        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,

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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.

Tax Risks

        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 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. 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 our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders 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.

        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 our unitholders. 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.

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        The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.

        Because a unitholder will be treated as a partner to whom we will allocate taxable income that could be different in amount than the cash 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 their share of our taxable income even if the unitholder receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

        We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take or may 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 the positions we take or may take. 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 an 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.

        If a unitholder sells his or her common units, a gain or loss will be recognized for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units they sell will, in effect, become taxable income to them if they sell such common units at a price greater than their tax basis in those common units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized on any sale of their 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 our unitholders sell their common units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

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        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. 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 our unitholders are a tax-exempt entity or a non-U.S. person, such unitholders should consult a tax advisor before investing in our common units.

        Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted 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 our unitholders. It also could affect the timing of these tax benefits or the amount of gain from their sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders tax returns.

        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. Recently, however, the U.S. Treasury Department issued proposed regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. 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.

        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. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to

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modify any applicable brokerage account agreements to prohibit their brokers from loaning their 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.

        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.

        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

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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 South 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 our unitholders responsibility to file all federal, state and local tax returns.

Item 1B.    Unresolved Staff Comments

        None.

Item 2.    Properties

        Our real property falls into two categories:

        Portions of the land on which our plants and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our plant sites and major facilities are located are held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessors.

        We are not aware of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses. A description of our properties is included in Item 1—"Business" and incorporated herein by reference.

Item 3.    Legal Proceedings

        From time-to-time, we are party to certain legal, regulatory or administrative proceedings that arise in the ordinary course and are incidental to our business. There are currently no such pending proceedings to which we are a party that our management believes will have a material effect on our results of operations, cash flows or financial condition.

        On March 5, 2013, a subsidiary of the Partnership filed suit against Formosa. The lawsuit seeks recoveries of losses which we believe our subsidiary experienced as a result of Formosa's failure to perform certain of its obligations under the gas processing contract between the parties. We cannot predict the outcome of such litigation.

Item 4.    Mine Safety Disclosures

        Not applicable.

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PART II

        

Item 5.    Market For Registrant's Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities

Market Information

        Our common units have been listed on the New York Stock Exchange since November 7, 2012 under the symbol "SXE." The following table sets forth the high and low sales prices of our common units and the per unit distributions declared for the quarter ended December 31, 2012. Distributions are recorded when paid.

 
   Unit Prices    
    
    
 
   Distributions
per common unit 		   
    
 
   High   Low   Record date   Payment date

Quarter Ended

   $ 23.96   $ 22.08   $ 0.24 (2) February 11, 2013   February 14, 2013

December 31, 2012(1)

                          
(1)
From November 7, 2012, the day our common units began trading on the NYSE through December 31, 2012.

(2)
Pro-rated cash distribution for the portion of the quarter following the closing of the Partnership's IPO on November 7, 2012 which corresponds to the minimum quarterly distribution of $0.40 per unit or $1.60 on an annualized basis.

        The last reported sale price of our common units on the NYSE on April 9, 2013, was $19.98 and there were 3,198 unitholders of record of our common units. As of April 9, 2013, we have issued 12,213,713 subordinated units and 498,518 general partner units, for which there is no established trading market.

Distribution 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.

        Definition of Available Cash.    Available cash generally means, for any quarter, all cash on hand at the end of that quarter:

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        Working capital borrowings are generally borrowings that are made under a credit facility or another arrangement, are used solely for working capital purposes or to pay distributions to unitholders, and are intended to be repaid within 12 months.

        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 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 and requirements under our credit agreement.

General Partner Interest and Incentive Distribution Rights

        Our General Partner is currently entitled to 2% 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% 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% 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%, of the cash we distribute from operating surplus in excess of $0.46 per unit per quarter. The maximum distribution of 50% includes distributions paid to our General Partner on its 2% general partner interest and assumes that our General Partner maintains its general partner interest at 2%. The maximum distribution of 50% does not include any distributions that our General Partner may receive on any limited partner units that it owns.

        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% general partner interest and assume that our General Partner has contributed any additional capital necessary to maintain its 2% 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 %   2 %

First target distribution

   $0.40 up to $0.46     98 %   2 %

Second target distribution

   above $0.46 up to $0.50     85 %   15 %

Third target distribution

   above $0.50 up to $0.60     75 %   25 %

Thereafter

   above $0.60     50 %   50 %

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Performance Graph

        The following performance graph compares the cumulative total unitholder return of our common units with the Standard & Poor's 500 Stock Index ("S&P 500") and the Alerian MLP Index for the period from our IPO (November 7, 2012) to December 31, 2012, assuming an initial investment of $100.


Comparison of Cumulative Total Return

GRAPHIC

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Item 6.    Selected Financial Data

        The information in this section should be read in conjunction with Part II, Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations", and Item 8., "Financial Statements and Supplementary Data." The preparation of our consolidated financial statements requires us to make a number of significant judgments and estimates, as well as consider a number of uncertainties. As such, the information reflected in the table below may not be indicative of our future results of operations or financial condition. The following table includes selected financial data as of and for each of the four years from Southcross Energy LLC's predecessor's inception through the period ended December 31, 2012 (in thousands, except per unit data and volume data).

 
    
    
    
    
    
   Southcross
Energy LLC's
Predecessor 		 
 
    
    
    
    
    
  
 
   Year Ended December 31,    
  




 
 
   June 2, 2009
through
December 31, 2009(1) 		  January 1, 2009
through
July 31, 2009 		 
 
   2012(1)   2011(1)   2010(1)  

Statement of operations data:

                                    

Revenues

   $ 496,129   $ 523,149   $ 498,747   $ 206,634       $ 330,870  

Income from operations

   $ 3,289   $ 16,388   $ 19,733   $ 9,325       $ 1,798  

Net income (loss)

   $ (4,488 ) $ 7,539   $ 9,719   $ 4,408       $ 1,721  

Less:

                                    

Net loss from January 1, 2012 through

                                    

November 6, 2012

     (260 )                            
                                   

Net loss for partners

   $ (4,228 )                            

General partner's interest

    
(85
)		                            
                                   

Limited partners' interest

   $ (4,143 )                            
                                   

Net loss from January 1, 2012 through November 6, 2012

    
(260
)		                            

Less deemed dividend on:

                                    

Redeemable preferred units

     (2,693 )   (1,553 )   —     —         —  

Series B redeemable preferred units

     (4,696 )   —     —     —         —  

Series C redeemable preferred units

     (2,012 )   —     —     —         —  

Preferred units

     (13,249 )   (14,131 )   (12,802 )   (4,818 )       —  
                           

Net loss attributable to Southcross Energy LLC common unitholders

   $ (22,910 ) $ (8,145 ) $ (3,083 ) $ (410 )     $ 1,721  
                           

Basic and diluted earnings per unit

                                    

Net loss allocated to limited partner common units (from November 7, 2012 through December 31, 2012)

   $ (2,072 )                            

Weighted average number of limited partner common units outstanding

     12,213,713                              

Loss per common unit

   $ (0.17 )                            

Net loss allocated to Southcross Energy LLC common units

  
$
(22,910
)
$
(8,145
)
$
(3,083
)
$
(410
)		    
$
1,721		  

Weighted average number of Southcross Energy LLC common units outstanding

     1,198,429     1,197,876     1,197,257     1,197,007         n/a  

Loss per Southcross Energy LLC common unit(2)

   $ (19.12 ) $ (6.79 ) $ (2.57 ) $ (0.34 )     $ n/a  

Performance measures:

                                    

Distributions declared per unit(3)

   $ 0.24   $ n/a   $ n/a   $ n/a       $ n/a  

Other financial data:

                                    

Adjusted EBITDA(4)

   $ 24,019   $ 28,957   $ 30,869   $ 16,517       $ 9,236  

Gross operating margin(4)

   $ 71,640   $ 62,569   $ 59,316   $ 27,589       $ 29,502  

Maintenance capital expenditures

   $ 5,193   $ 5,317   $ 3,402   $ 3,025       $ 565  

Expansion capital expenditures

   $ 164,623   $ 150,669   $ 1,843   $ 1,669       $ 250  

Operating data:

                                    

Average throughput volumes of natural gas (MMBtu/d)

     553,093     506,975     471,265     492,350         592,243  

Average volume of processed gas (MMBtu/d)

     206,045     155,475     153,557     166,018         188,642  

Average volume of NGLs sold (Bbls/d)

     9,385     5,131     5,557     5,369         5,757  

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

   $ 2.83   $ 4.05   $ 4.42   $ 3.97       $ 3.95  

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

   $ 0.87   $ 1.35   $ 1.10   $ 1.01       $ 0.69  

Balance sheet data (at period end):

                                    

Cash and cash equivalents

   $ 7,490   $ 1,412   $ 20,323   $ 5,724            

Trade accounts receivable

   $ 50,994   $ 41,234   $ 35,059   $ 39,956            

Property, plant, and equipment, net

   $ 550,603   $ 369,861   $ 229,309   $ 235,065            

Total assets

   $ 618,605   $ 420,385   $ 289,643   $ 287,808            

Total debt (current and long term)

   $ 191,000   $ 208,280   $ 115,000   $ 119,949            
(1)
Reflects financial data of Southcross Energy Partners, L.P. from November 7, 2012 to December 31, 2012 subsequent to our IPO, and Southcross Energy LLC for periods ending prior to November 7, 2012.

(2)
Earnings per unit of Southcross Energy LLC prior to the initial public offering of Southcross Energy Partners, L.P.

(3)
A distribution of $0.24 attributable to fourth quarter 2012 is the first distribution declared by the Partnership and corresponds to the minimum quarterly distribution of $0.40 per unit, or $1.60 on an annualized basis, pro-rated for the portion of the quarter following the closing of the Partnership's initial public offering on November 7, 2012. This distribution was declared and paid in February 2013 therefore no accrual was required as of December 31, 2012.

(4)
See Part II. Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" for definition of Non-GAAP financial metrics and reconcilation of Non-GAAP metrics to its most directly comparable GAAP financial measure.

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Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations

        The following is a discussion of our historical consolidated financial condition and results of operations that is intended to help the reader understand our business, results of operations and financial condition. It should be read in conjunction with other sections of this report, including our historical consolidated financial statements and accompanying notes thereto included in Part II—Item 8 of this report.

        This Management's Discussion and Analysis and Financial Condition and Results of Operations includes the following sections:

Overview and How We Evaluate our Operations

Overview

        Southcross Energy Partners, L.P. (the "Partnership," "Southcross," the "Company", "we", "our" or "us"), which closed its initial public offering ("IPO") on November 7, 2012, is a Delaware limited partnership formed in April 2012. Southcross Energy LLC is a Delaware limited liability company, and Southcross Energy LLC is our predecessor for accounting purposes (the "Predecessor"). References in this Form 10-K to the Partnership or the Company, when used for periods prior to the IPO, refer to Southcross Energy LLC and its consolidated subsidiaries, unless otherwise specifically noted. References in this Form 10-K to the Partnership or the Company, when used for periods beginning at or following the IPO, refer collectively to the Partnership and its consolidated subsidiaries. This report reflects the consolidated assets, liabilities, results of operations and cash flows of Southcross Energy Partners, L.P. beginning November 7, 2012 and Southcross Energy LLC for periods ending prior to November 7, 2012.

        The Partnership provides natural gas gathering, processing, treating, compression and transportation services and natural gas liquid ("NGL") fractionation and transportation services for its producer customers. We also source, purchase, transport and sell natural gas and NGLs to our power generation, industrial and utility customers. Our assets are located in South Texas, Mississippi and Alabama and as of December 31, 2012 include three gas processing plants, two NGL fractionation plants and approximately 2,700 miles of pipeline. Our South Texas assets operate in or within close proximity to the Eagle Ford shale region. Our assets are strategically positioned to provide transportation of natural gas and NGLs to power generation, industrial and utility customers as well as to unaffiliated intrastate and interstate pipelines. The Partnership is a midstream natural gas company and operates as one reportable segment.

Industry Conditions and Trends

        Our business environment and corresponding operating results are affected by key trends discussed below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove

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to be incorrect, our actual results may vary materially from our expected results. Key trends that we monitor while managing our business include natural gas supply and demand dynamics overall and in our markets as well as growth production from U.S. shale plays, with specific attention on the Eagle Ford shale region.

        A critical component of energy supply and demand in the United States is natural gas. Recently, the price of natural gas has been at relatively low levels. The primary driver behind this trend is increased production, especially from unconventional sources, such as natural gas shale plays, high levels of natural gas in storage and warm winter weather.

        According to the U.S. Energy Information Administration, average annual natural gas production in the United States increased significantly from 2008 through 2011 with modest growth of natural gas consumption over the same period, thereby increasing storage. According to the Texas Railroad Commission, well permits increased from 2011 to 2012 in the Eagle Ford shale region by approximately 47% from 2,826 to 4,143 permitted.

        We believe that growth opportunities for our business through increased demand for natural gas are likely to occur, especially as there is continued increased use of natural gas production in locations such as the Eagle Ford shale region.

Our Operations

        Our integrated operations provide a full range of complementary services from wellhead to market, including gathering natural gas at the wellhead, treating natural gas to meet downstream pipeline and customer quality standards, transporting natural gas and NGLs on our pipeline, processing natural gas to separate the NGLs from the natural gas, fractionating the resulting NGLs into the various components and selling or delivering pipeline quality natural gas and NGLs to various industrial and energy markets as well as interstate pipeline systems. Through our network of pipelines, we connect our suppliers of natural gas to our customers, which include local distribution companies, and industrial, commercial and power generation customers.

        Our results are determined primarily by the volumes of natural gas we gather and process, the efficiency of our processing plants and NGL fractionation plants, the commercial terms of our contractual arrangements, natural gas and NGL prices, and our operations and maintenance expense. We manage our business to attempt to maximize the gross operating margin we earn from contracts balanced against any risks we assume in our contracts. Our contracts vary in duration from one month to ten years and the pricing under our contracts varies depending upon several factors, including our competitive position, our acceptance of risks associated with longer-term contracts and our desire to recoup over the term of the contract any capital expenditures that we are required to incur in order to provide service to our customers. We purchase, gather, process, transport and sell natural gas and purchase, fractionate, and sell NGLs primarily pursuant to the following arrangements:

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        We assess gross operating margin opportunities across our integrated value stream, so that processing margins may be supplemented by gathering and transportation fees and opportunities to sell residue gas at fixed-spreads. Gross operating margin earned under fixed-fee and fixed-spread arrangements is directly related to the volume of natural gas that flows through our systems and is generally independent from general commodity price levels. A sustained decline in commodity prices could result in a decline in volumes entering our system and, thus, a decrease in gross operating margin for our fixed-fee and fixed-spread arrangements.

        Below is a table summarizing our contract mix (in thousands):

 
   Year ended December 31,  
 
   2012   2011   2010  
 
   Gross
margin 		  Percent of total
gross operating
margin 		  Gross
margin 		  Percent of total
gross operating
margin 		  Gross
margin 		  Percent of total
gross operating
margin 		 

Fixed-fee

   $ 48,055     67.0 % $ 32,340     51.7 % $ 27,541     46.4 %

Fixed-spread

     18,737     26.2 %   14,544     23.2 %   15,521     26.2 %
                           

Sub-total

     66,792     93.2 %   46,884     74.9 %   43,062     72.6 %

Commodity sensitive

     4,848     6.8 %   15,685     25.1 %   16,254     27.4 %
                           

Total gross operating margin

   $ 71,640     100.0 % $ 62,569     100.0 % $ 59,316     100.0 %
                           

How We Evaluate Our Operations

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

        Volume—We determine and analyze volumes by operating unit, but report overall volumes after elimination of intercompany deliveries. The volume of natural gas and NGLs on our systems depends on the level of production from natural gas wells connected to our systems and also from wells connected with other pipeline systems that are interconnected with our systems.

        Gross Operating Margin—Gross operating margin of our contracts is one of the metrics we use to measure and evaluate our performance. Gross operating margin is not a measure calculated in accordance with accounting principles generally accepted in the United States of America ("GAAP"). We define gross operating margin as the sum of contract revenues less the cost of natural gas and NGLs sold. For our fixed-fee contracts, we record the fee as revenue and there is no offsetting cost of

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natural gas and NGLs sold. For our fixed-spread and commodity-sensitive arrangements, we record as revenue all of our proceeds from the sale of the natural gas or NGLs and record as an expense the associated cost of natural gas and NGLs sold.

        Operations and Maintenance Expense—Our management seeks to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating and maintaining our assets. Direct labor costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities, and contract services comprise the most significant portion of our operations and maintenance expense. These expenses are relatively stable and largely independent of volumes delivered through our systems, but may fluctuate depending on the activities performed during a specific period.

        Adjusted EBITDA and Distributable Cash Flow—We believe that Adjusted EBITDA is a widely accepted financial indicator of our operational performance and ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA is not a measure calculated in accordance with GAAP, as it does not include deductions for items such as depreciation, amortization, interest and income taxes, which may be necessary to maintain the business. We define Adjusted EBITDA as net income, plus interest expense, income tax expense, depreciation and amortization expense, certain non-cash charges such as non-cash equity compensation, unrealized losses on commodity derivative contracts and selected charges and transaction costs that are unusual or non-recurring, less interest income, income tax benefit, unrealized gains on commodity derivative contracts and selected gains that are unusual or non-recurring. Adjusted EBITDA should not be considered an alternative to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP.

        Adjusted EBITDA is used as a supplemental measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

        We define distributable cash flow as Adjusted EBITDA plus interest income, less cash paid for interest expense, taxes and maintenance capital expenditures and use distributable cash flow to analyze our performance. Distributable cash flow does not reflect changes in working capital balances.

        Distributable cash flow is used to assess:

Non-GAAP Financial Measures

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

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operations. Net income is the GAAP measure most directly comparable to each of gross operating margin and Adjusted EBITDA. The GAAP measure most directly comparable to distributable cash flow is net cash provided by operating activities. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as an analytical tool because each excludes some but not all items that affect the most directly comparable GAAP financial measure. You should not consider any of gross operating margin, Adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross operating margin, Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

Reconciliations of Non-GAAP financial Measures

        The following table presents a reconciliation of gross operating margin to net (loss) income (in thousands):

 
   Year ended December 31,  
 
   2012   2011   2010  

Gross operating margin

   $ 71,640   $ 62,569   $ 59,316  

Add (deduct):

                    

Income tax expense

     (246 )   (261 )   (1 )

Interest expense

     (5,767 )   (5,348 )   (10,013 )

Loss on extinguishment of debt

     (1,764 )   (3,240 )   —  

General and administrative expense

     (13,842 )   (9,129 )   (7,490 )

Depreciation and amortization expense

     (18,977 )   (12,345 )   (10,987 )

Operations and maintenance expense

     (35,532 )   (24,707 )   (21,106 )
               

Net (loss) income

   $ (4,488 ) $ 7,539   $ 9,719  
               

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        The following table presents a reconciliation of net cash flows provided by operating activities to net (loss) income, Adjusted EBITDA, and distributable cash flow (in thousands):

 
   Year ended December 31,  
 
   2012   2011   2010  

Net cash flows provided by operating activities

  $ 24,323   $ 20,007   $ 25,493  

Add (deduct):

                    

Depreciation and amortization expense

     (18,977 )   (12,345 )   (10,987 )

Unit-based compensation

     (630 )   —     —  

Loss on extinguishment of debt

     (1,764 )   (3,240 )   —  

Deferred financing costs amortization

     (1,183 )   (882 )   (2,158 )

Gain on sales of plant, property and equipment

     —     522     13  

Unrealized derivatives loss

     (141 )   (21 )   —  

Changes in operating assets and liabilities:

                    

Trade accounts receivable

     9,760     2,806     (4,897 )

Prepaid expenses and other

     1,246     497     (560 )

Other non-current assets

     (1,786 )   2,155     (158 )

Accounts payable and accrued expenses

     (16,517 )   (2,759 )   3,836  

Accrued expenses and other liabilities

     1,181     799     (863 )
               

Net (loss) income

  $ (4,488 ) $ 7,539   $ 9,719  
               

Add (deduct):

                    

Depreciation and amortization expense

     18,977     12,345     10,987  

Interest expense

     5,767     5,348     10,013  

Unrealized derivatives loss

     141     21     —  

Loss on extinguishment of debt

     1,764     3,240     —  

Unit-based compensation

     630     —     —  

Transaction costs

     —     203     149  

Income tax expense

     246     261     1  

Management fees

     568     —     —  

Expenses associated with significant items

     414     —     —  
               

Adjusted EBITDA

  $ 24,019   $ 28,957   $ 30,869  
               

Add (deduct):

                    

Cash interest, net

     (4,584 )   (4,466 )   (7,855 )

Income tax expense

     (246 )   (261 )   (1 )

Maintenance capital expenditures

     (5,193 )   (5,317 )   (3,402 )
               

Distributable cash flow

  $ 13,996   $ 18,913   $ 19,611  
               

Current Year Highlights

        The following events took place during 2012 and in early 2013 and have impacted or are likely to impact our financial condition and results of operations. The following should be read in conjunction with Part I, Item 1., "Business" of this report for a more detailed account of such events.

Financing Activities

        In connection with the closing of the IPO:

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        The Partnership may utilize its senior secured credit facility for working capital requirements and capital expenditures, the purchase of assets, the payment of distributions, repurchase of units and general purposes of the Partnership. For a complete description of Long-Term Debt, see Part II, Item 8, "Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 6—Long-Term Debt".

Key Factors Affecting Operating Results and Financial Condition

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        As discussed above, during the fourth quarter 2012 and into first quarter 2013 we encountered operational difficulties related to a startup of our new Bonnie View NGL fractionator, curtailments and other actions by our third-party processor, and a fire on January 26, 2013 at our Gregory facility that prolonged the shutdown of the facility. We believe these items are now largely behind us. We completed the expansion of our Bonnie View NGL fractionator in February 2013. In addition, our Gregory facility became fully operational in April 2013 after repairing damage caused by the fire. These items, however, adversely impacted our operating results in the fourth quarter of 2012 and into the first quarter of 2013. As a result of this negative impact, we believed it was unlikely that we would be in compliance with our financial covenants calculated for the quarter ending March 31, 2013, such that we negotiated with our lenders and secured more favorable financial covenants and amended our Credit Facility. As a result of the amendments and after giving effect of the equity infusion and its use to repay debt on April 12, 2013, we have $27.2 million of borrowing capacity under our amended Credit Facility. Consequently, we believe we have and will continue to have sufficient liquidity to operate our business as the amended Credit Facility provides us with more favorable financial covenants than were provided previously and we believe these more favorable terms will allow us to operate our business and continue to meet our commitments. Please read "Liquidity and Capital Resources—Long-Term Debt" for a description of the amendments we have entered into with respect to our Credit Facility.

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Results of Operations

        The following table summarizes our results of operations (in thousands, except operating data):

 
   Year ended December 31,  
 
   2012   2011   2010  

Revenues

   $ 496,129   $ 523,149   $ 498,747  

Expenses:

                    

Cost of natural gas and liquids sold

     424,489     460,580     439,431  

Operations and maintenance

     35,532     24,707     21,106  

Depreciation and amortization

     18,977     12,345     10,987  

General and administrative

     13,842     9,129     7,490  
               

Total expenses

     492,840     506,761     479,014  
               

Income from operations

     3,289     16,388     19,733  

Loss on extinguishment of debt

     (1,764 )   (3,240 )   —  

Interest expense

     (5,767 )   (5,348 )   (10,013 )
               

(Loss) income before income tax expense

     (4,242 )   7,800     9,720  

Income tax expense

     (246 )   (261 )   (1 )
               

Net (loss) income

  $ (4,488 ) $ 7,539   $ 9,719  
               

Other financial data:

                    

Adjusted EBITDA

   $ 24,019   $ 28,957   $ 30,869  

Gross operating margin

   $ 71,640   $ 62,569   $ 59,316  

Maintenance capital expenditures

   $ 5,193   $ 5,317   $ 3,402  

Expansion capital expenditures

   $ 164,623   $ 150,669   $ 1,843  

Operating data:

                    

Average throughput of gas (MMBtu/d)

     553,093     506,975     471,265  

Average volume of processed gas (MMBtu/d)

     206,045     155,475     153,557  

Average volume of NGLs sold (Bbls/d)

     9,385     5,131     5,557  

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

   $ 2.83   $ 4.05   $ 4.42  

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

   $ 0.87   $ 1.35   $ 1.10  

        The following table summarizes our average natural gas throughput volumes, amount of NGLs delivered, and volume of processed gas:

 
   Year ended December 31,  
 
   2012   2011   2010  

Average throughput volumes of natural gas (MMBtu/d)

                    

South Texas

     352,458     363,545     343,317  

Mississippi/Alabama

     200,635     143,430     127,948  
               

Total average throughput volumes of natural gas

     553,093     506,975     471,265  
               

Average volume of NGLs sold (Bbls/d)

     9,385     5,131     5,557  

Average volume of processed gas (MMBtu/d)

     206,045     155,475     153,557  

2012 Compared with 2011

        Volume and overview—Our average throughput volume of natural gas increased by 9.1% to 553,093 MMBtu/d in 2012 compared to 506,975 MMBtu/d in 2011. The increase was driven primarily by our

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Mississippi/Alabama systems which increased 39.9% in 2012 due to twelve months of throughput on our pipeline and gathering system that we acquired from Enterprise Alabama Intrastate, LLC ("EAI") in September 2011 compared to four months of activity in 2011. Our South Texas throughput volumes in 2012 decreased by 3.0% compared to 2011. This decrease in our South Texas throughput volumes reflects the offsetting effects of declining lean gas supply and increasing rich gas supply, the latter of which was largely timed to occur as we increased our processing and fractionation capacity late in 2012. NGLs sold increased by 82.9% to 9,385 Bbls/d in 2012 primarily the result of an increase in rich gas volumes processed at our facilities from the Eagle Ford Share area.

        Our gross operating margin increased by 14.5% to $71.6 million in 2012, primarily the result of higher processing fees and gathering fees and the benefit of eight additional months of operations from the acquisition of EAI which offset negative effects occurring during 2012 of lost revenue during startup of facilities, curtailments of processed volumes and other negative factors.

        The Partnership incurred a net loss of $4.5 million in 2012 compared to net income of $7.5 million in 2011. This was due primarily to higher operations and maintenance expenses of $10.8 million, a $6.6 million increase in depreciation and amortization expense, and a $4.7 million increase in general and administrative expenses resulting from the growth of our business exceeding the benefits of our higher gross operating margin. As a result of our recapitalization in 2012, we incurred a loss on extinguishment of debt, which was lower than such loss in 2011. Adjusted EBITDA decreased 17.1% to $24.0 million in 2012 compared to $29.0 million in the prior year, due primarily to higher operations and maintenance expense, and general and administrative expenses as stated above, offset by an improvement in gross operating margin. We estimate the impact to Adjusted EBITDA due to processing plant outages and curtailments at the Formosa processing plant in 2012 was approximately $5.3 million.

        Revenue—Our revenue for 2012 was $496.1 million compared to $523.1 million in 2011. The decrease of $27.0 million or 5.2% was due primarily to lower pricing of natural gas and NGL products, partially offset by a 9.1% increase in throughput volumes and 82.9% increase in NGLs sold as discussed above. We realized average natural gas and NGL prices of $2.83/MMBtu and $0.87/gal, respectively, in 2012 compared to $4.05/MMBtu and $1.35/gal, respectively, in 2011.

        Cost of natural gas and NGLs sold—The cost of natural gas and liquids sold was $424.5 million in 2012 compared to $460.6 million in 2011. The $36.1 million or 7.8% decrease was due to lower prices of natural gas and NGLs offset by the cost of increased NGL volumes.

        Operations and maintenance expense—Operations and maintenance expense increased $10.8 million or 43.8% to $35.5 million in 2012. This increase was due primarily to $4.0 million related to the startup of the Woodsboro and Bonnie View facilities, $2.1 million resulting from the inclusion of eight additional months of the EAI pipeline and gathering system, $3.0 million at our Gregory processing facility for outages and a maintenance turnaround in December 2012, increased pipeline integrity costs of $0.6 million, $0.4 million in higher equipment and vehicle rentals, increased cathodic protection costs of $0.3 million, and higher other operations and maintenance expenses of $0.6 million.

        General and administrative ("G&A") expense—G&A expenses were $13.8 million in 2012 compared to $9.1 million in 2011 representing a $4.7 million or 51.6% increase. This increase was due primarily to increased employment-related expenses of $3.3 million and increased professional fees of $1.0 million, both primarily associated with preparing to become and then becoming a publicly traded master limited partnership, and increased insurance of $0.4 million, as we continued to build out our corporate and support infrastructure.

        Depreciation and amortization expense—Depreciation and amortization expense was $19.0 million for 2012 or an increase of $6.6 million or 53.7%. The increase in this expense primarily was the result

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of the EAI acquisition in September 2011 and growth capital expenditures made during the second half of 2011 and in 2012.

        Loss on extinguishment of debt—In 2012, we incurred a loss on the extinguishment of debt of $1.8 million in connection with the repayment of $270.0 million of Southcross Energy LLC's assumed debt balance following our IPO consisting of a partial write-down of deferred financing costs. In 2011, we incurred a loss on the extinguishment of debt of $3.2 million relating to the partial write-down of deferred financing costs on a previous credit agreement which was amended in June 2011.

        Interest expense—Net interest expense increased $0.4 million, or 7.8%, to $5.8 million in 2012 compared to $5.3 million in 2011. The increase was due to higher average borrowings of $230.4 million in 2012 compared to $147.4 million in 2011, partially offset by increased capitalized interest of $6.3 million in 2012 compared to $1.8 million in 2011. For the years ended December 31, 2012 and December 31, 2011, our average effective interest rate, as calculated for financial reporting purposes, was 3.95% and 3.58%, respectively.

2011 Compared with 2010

        Volume and overview—Our average throughput volume of natural gas increased by 7.6% to 506,975 MMBtu/d in 2011, compared to 471,265 MMBtu/d in 2010. Our South Texas throughput volumes in 2011 increased by 5.9% compared to the same period in 2010. This increase in our South Texas throughput volumes reflects stronger activity through our system in the last four months of 2011, in part as a result of new contracts that we executed to support the completion of our McMullen pipeline extension. Our volumes in South Texas were unfavorably impacted by two events during 2011: (i) the shutdown of our Gregory processing plant for 31 days during June and July in order to repair a dehydrator unit; and (ii) a 31 day shutdown in September and October by Formosa at its processing plant in order to complete an expansion construction project, which forced us to shutdown natural gas supply to, and interrupted processing at, this facility. Our Mississippi and Alabama throughput volumes were up 12.1% for 2011 compared to 2010. This increase is due to the inclusion of four months of throughput on our pipeline and gathering system that we acquired in connection with the EAI acquisition in 2011. Without this additional volume, our average daily throughput volumes would have declined by 17.2% for our Mississippi and Alabama assets for 2011 compared to 2010. This decline was due primarily to lower demand from the South Mississippi Electric Power Association, or SMEPA, and the impact on our Delta Pipeline resulting from the flooding of the Mississippi River in the second quarter of 2011. For NGLs, the average volume delivered per day for 2011 was 215.5 Mgal, compared to 233.4 Mgal for 2010, a decrease of 7.7%. This decrease was due in part to the shutdown of our Gregory processing plant for 31 days in June and July 2011 and severe cold weather in February and March 2011. Without the Gregory processing plant shutdown, we estimate our average daily volume delivered would have been 225.4 Mgal for 2011.

        Our gross operating margin in 2011 improved to $62.6 million compared to $59.3 million in 2010, an increase of 5.5%, primarily as a result of slightly higher treating / producer fee-based revenues as well as a greater price spread between NGL and natural gas prices and the benefit of four months of operations from the EAI acquisition, which more than offset lower NGL volumes. We estimate that our gross operating margin in 2011 was negatively impacted by $2.1 million as a result of the unexpected closure of our Gregory processing plant and the forced closures of the Formosa processing plant in September and October 2011. For part of the year, we were capacity bound by our inability to process all of the wet gas in our system. This constraint was the impetus for our future growth capital expenditure plans and the construction of the Bonnie View NGL fractionation plant. We generated net income for 2011 of $7.5 million compared to net income of $9.7 million for 2010. This decrease was due primarily to a loss on extinguishment of debt of $3.2 million, higher operating and maintenance expenses of $3.6 million and increased depreciation and amortization expense of $1.3 million, partially offset by lower interest expense. Adjusted EBITDA decreased by 6.3% to $28.9 million in 2011

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compared to $30.9 million in 2010, due primarily to higher operating and maintenance expenses and increased G&A expenses, partially offset by an improvement in gross operating margin.

        Revenue—Our total revenue in 2011 was $523.1 million, compared to $498.7 million in 2010. This increase of $24.4 million, or 4.9%, was due primarily to the inclusion of four months of results from the EAI acquisition, which contributed $11.0 million in revenues. We also had a 22.7% increase in realized average NGL prices, a 17.4% increase in fee-based revenues, partially offset by a 7.7% decline in NGL volumes. We realized average natural gas and NGL prices of $4.05/MMBtu and $1.35/gal, respectively, in 2011 compared to $4.42/MMBtu and $1.10/gal, respectively, in 2010.

        Cost of natural gas and NGLs sold—Our cost of natural gas and liquids sold in 2011 was $460.6 million compared to $439.4 million in 2010. This increase was due to the increased natural gas throughput in South Texas and, in part, to the inclusion of four months of throughput on our Alabama pipeline and gathering system that we acquired in 2011.

        Operations and maintenance expense—The expenses related to operating and maintaining our assets in 2011 were $24.7 million compared to $21.1 million in 2010. This increase of $3.6 million was due primarily to the inclusion of four months of expenses relating to the operation of the EAI pipeline and gathering system, increased expenditures on pipeline integrity, higher expenses for chemicals used at our facilities and building up our engineering capability to support our expansion plans.

        General and administrative ("G&A") expenses—G&A expenses in 2011 were $8.9 million compared to $7.3 million in 2010. This increase of $1.6 million was due primarily to increased employment-related expenses as we continued to build up our corporate infrastructure. We incurred approximately $0.2 million of acquisition-related expenses, including legal, consulting and professional fees in 2011 in connection with the acquisition of EAI on September 1, 2011. This compares to $0.1 million of transaction costs for bank fees related to our acquisition of the Crosstex Energy, L.P. assets that we incurred in 2010.

        Depreciation and amortization expense—Depreciation and amortization expense in 2011 was $12.3 million compared to $11.0 million in 2010 primarily as a result of the EAI acquisition and growth capital expenditures made during 2011.

        Loss on extinguishment of debt—For 2011, we recorded a loss on the extinguishment of debt of $3.2 million relating to the write off of deferred financing fees on our previous credit agreement as a result of entering into our existing credit agreement on June 10, 2011.

        Interest expense—In 2011, interest expense was $5.4 million, compared to $10.0 million in 2010. This decrease was due primarily to $1.8 million of interest expense being capitalized in 2011 as part of construction costs of our new facilities, the lower amortization of deferred financing fees in 2011 compared to 2010, and favorable interest rate margins obtained under an amendment to our credit agreement that we entered into on December 30, 2010. For the years ended December 31, 2011 and December 31, 2010, our average effective interest rate, as calculated for financial reporting purposes, was 3.58% and 8.90%, respectively.

Liquidity and Capital Resources

Sources of Liquidity

        Cash generated from operations, investments by Charlesbank and other investors, and borrowings under our Predecessor's Amended and Restated Credit Agreement dated June 10, 2011, ("Southcross' Credit Agreement") and the Partnership's Second Amended and Restated $350 million senior secured credit facility, dated as of November 7, 2012, as amended (the "Credit Facility") have been our primary sources of historical liquidity. Prior to our IPO, our primary cash requirements consisted of operating and G&A expenses, capital expenditures to sustain existing operations or generate additional revenues, interest payments on outstanding debt and acquisitions of new assets or businesses.

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        The Partnership expects to fund short term cash requirements, such as operating and G&A expenses and maintenance capital expenditures to sustain existing operations, primarily through operating cash flows. We expect to fund long-term cash requirements, such as for expansion projects and acquisitions, through several sources, including operating cash flows, borrowings under our Credit Facility and issuances of additional equity and debt securities, as appropriate and subject to market conditions. The Partnership's ability to fund expansion projects through the use of its Credit Facility is limited during the remainder of 2013 and the 18 month period ending June 30, 2015 under the amendments entered into on March 27, 2013 and April 12, 2013. The Partnership does not expect these limitations to significantly affect current operations or future projects. See "Long-Term Debt" below for a description of the amendments to the Credit Facility.

        Capital resources.    The Partnership's business is capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of and will continue to be:

        During the year ended December 31, 2012, capital expenditures totaled $169.8 million, consisting of $5.2 million of maintenance capital and $164.6 million of expansion capital. The expansion capital expenditures during 2012 related mainly to (i) our 200 MMcf/d Woodsboro processing plant in Refugio County, Texas, (ii) our Bonnie View NGL fractionation facility, and (iii) our new Bee Line pipeline which was completed in February 2013.

        Outlook.    Cash flow is affected by a number of factors, some of which we cannot control. These factors include prices and demand for our services, operational risks, volatility in commodity prices or interest rates, industry and economic conditions, conditions in the financial markets, and other factors.

        Commodity prices and financial market conditions continue to support opportunities for volume growth from shale resource plays. The Partnership's ability to benefit from growth projects to accommodate strong drilling activity is subject to operational risks and uncertainties such as the uncertainty inherent in some of the assumptions underlying design specifications for new, modified or expanded facilities. These risks also impact third-party service providers and their facilities. Delays or underperformance of our facilities or third-party facilities may adversely affect our ability to generate cash from operations and comply with our obligations, including the covenants under our debt instruments. For example, we encountered operational difficulties in connection with the start-up of our Bonnie View fractionator, the curtailment by our third party operator and a fire at our Gregory Facility that had a negative impact on our results in the fourth quarter of 2012 and first quarter 2013. In other cases, actual production delivered may fall below volume estimates that we relied upon in deciding to pursue an acquisition or other growth project. Future cash flow and the Partnership's ability to comply with its debt covenants would likewise be affected adversely if we experienced declining volumes over a sustained period in combination with unfavorable commodity prices.

        Our historical financing strategy for funding long-term capital expenditures has been to target a roughly equal mix of debt and equity financing and a consolidated leverage ratio which complied with our credit agreement covenants. During the fourth quarter 2012 and into the first quarter 2013 we encountered operational difficulties having an adverse impact our operating results. As a result of this

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negative impact, we believed it was unlikely that we would be in compliance with our financial covenants calculated for the quarter ending March 31, 2013, such that we negotiated with our lenders and secured more favorable financial covenants and amended our Credit Facility. As a result of the amendments to the Credit Facility, and after giving effect of the equity infusion and its use to repay debt on April 12, 2013, we have $27.2 million of borrowing capacity under our amended Credit Facility. Consequently, we believe we have and will continue to have sufficient liquidity to operate our business as the amended Credit Facility provides us with more favorable financial covenants than were provided previously and we believe these more favorable terms will allow us to operate our business and continue to meet our commitments. If the Partnership exceeds its target leverage ratio, as we expect we will from time to time for significant capital projects, acquisitions or other investments, we anticipate reducing leverage through the issuance of additional equity.

        Outstanding indebtedness decreased by $17.3 million to $191.0 million as of December 31, 2012 associated with our recapitalization in connection with the IPO. Debt outstanding was initially $150.0 million which was $120.0 million lower than our November 6, 2012 debt balance immediately prior to our IPO.

        We believe that cash from operations, cash on hand and available capacity under our amended Credit Facility will provide liquidity to meet future short term capital requirements and to fund committed capital expenditures for the remainder of 2013. The sufficiency of these liquidity sources to fund necessary and committed capital needs will be dependent upon our ability to meet our newly established covenant requirements of our amended Credit Facility. Please read "Liquidity and Capital Resource—Long-Term Debt" for a description of the amendments we have entered into with respect to our Credit Facility.

        Organic expansion projects and acquisitions are key elements of our business strategy. We intend to finance the Partnership's growth capital primarily through the issuance of debt and equity. The timing, size or success of any acquisition or expansion effort and the associated potential capital commitments are unpredictable. To consummate acquisitions or capital projects, we may require access to additional capital. Our access to capital over the longer term will depend on our future operating performance, financial condition and credit rating and, more broadly, on the availability of equity and debt financing, which will be affected by prevailing conditions in our industry, the economy and the financial markets and other financial and business factors, many of which are beyond our control.

Off-Balance Sheet Arrangements

        None.

Cash Flows

        The following table provides a summary of our cash flows by category (in thousands):

 
   Year ended December 31,  
 
   2012   2011   2010  

Net cash provided by operating activities

   $ 24,323   $ 20,007   $ 25,493  

Net cash used in investing activities

   $ (169,816 ) $ (144,602 ) $ (5,231 )

Net cash provided by (used in) financing activities

   $ 151,571   $ 105,684   $ (5,663 )

2012 Compared with 2011

        Operating Activities—Net cash provided by operating activities was $24.3 million in 2012, compared to $20.0 million in 2011. The increase in cash provided by operating activities of $4.3 million primarily was a result of the positive effect of a decline in the change in operating assets and liabilities of

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$9.6 million, driven primarily by growth in volumes and accrued operating and maintenance costs at our Gregory facility and higher ad valorem taxes. These factors were partially offset by lower net income, net of non-cash charges of $5.3 million.

        Investing Activities—Net cash used in investing activities was $169.8 million in 2012 compared to $144.6 million in 2011. The increase in cash used in investing activities primarily was a result of increases in expansion capital expenditures associated with our growth activities.

        Financing Activities—Net cash provided by financing activities was $151.6 million in 2012 compared to $105.7 million in 2010. The increase in cash provided by financing activities of $45.9 million primarily was a result of IPO proceeds of $187.8 million offset by distributions to Southcross Energy LLC of $71.2 million.

2011 Compared with 2010

        Operating activities—Net cash provided by operating activities was $20.0 million in 2011, compared to $25.5 million in 2010. The decrease in cash provided by operating activities primarily was a result of negative changes of $6.2 million in operating assets and liabilities related to interest payable, other non-current assets and prepaid assets, partially offset by the higher net income, net of non-cash charges of $0.7 million.

        Investing activities—Net cash used in investing activities was $144.6 million in 2011 compared to $5.2 million in 2010. The increase in cash used in investing activities primarily was a result of a significant increase in expansion capital expenditures associated with our growth plans and the payment of $21.8 million for the acquisition of EAI.

        Financing activities—Net cash provided by (used in) financing activities was $105.7 million in 2011 compared to ($5.7) million in 2010. The change in cash provided by financing activities primarily was a result of increased net borrowings of $93.3 million under our existing credit facility and a capital contribution of $15.0 million by Charlesbank and other existing investors, partially offset by the payment of debt amendment costs of $2.7 million in 2011 compared to the net repayment of debt of $4.9 million and payment of debt financing costs of $0.8 million in 2010.

Long-Term Debt

        During fourth quarter 2012 and into first quarter 2013 we encountered operational challenges caused by several events:

        These items negatively impacted our operating results and as a result of this negative impact we believed it was unlikely that we would be in compliance with our financial covenants calculated for the quarter ending March 31, 2013, such that we negotiated with our lenders and secured more favorable financial covenants associated with our Credit Facility.

        On March 27, 2013, we entered into the first amendment (the "First Amendment") to the Credit Facility. As a result of the First Amendment, our letters of credit sublimit was reduced from $75.0 million to $31.5 million and our available credit was reduced from $350.0 million to $250.0 million, plus the sum of any amounts placed on deposit in a collateral account of our General Partner (the "Collateral Account"), plus letters of credit outstanding. Our General Partner deposited

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$10.0 million into the Collateral Account as required under the First Amendment. Pursuant to the First Amendment, we are allowed to pay our quarterly cash distribution of available cash for the first quarter 2013 in an amount not to exceed the amount then on deposit in the Collateral Account. Because the First Amendment did not modify our requirement to meet the financial covenants under the Credit Facility beginning March 31, 2013 we further amended our Credit Facility as discussed below.

        On April 12, 2013 we entered into the limited waiver and second amendment (the "Second Amendment") to the Credit Facility which waived our defaults relating to financial covenants for the period ending March 31, 2013 and provided more favorable financial covenants until we give notice under the amended Credit Facility that we have achieved a Target Leverage Ratio (as defined in the Second Amendment) of 4.25 to 1.00 for one quarter or 4.50 to 1.00 for two consecutive quarters, calculated excluding the benefit of cash on deposit in the Collateral Account and any equity cure amounts (the "Target Leverage Test"). Our available credit continues to be subject to the availability limits described in the First Amendment.

        As a condition to the Second Amendment, Southcross Energy LLC and our General Partner deposited into the Collateral Account a total of $34.2 million, including the $10.0 million previously deposited under the First Amendment. Additionally, Southcross Energy LLC and our General Partner agreed to deposit into the Collateral Account the proceeds they receive from cash distributions on units in us that are attributable to the quarters ending March 31, 2013, June 30, 2013, September 30, 2013 and December 31, 2013.

        The Second Amendment provides for, among other things, the following:

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        If, for the calendar quarters ending on or before December 31, 2013, we fail to comply with the financial covenants of the Amended Credit Facility ("Financial Covenant Default") we have the right (which cannot be exercised more than two times) to cure such Financial Covenant Default by having Southcross Energy LLC and/or our General Partner deposit into the Collateral Account the amount required by the Second Amendment to cure such Financial Covenant Default.

        As of April 12, 2013, after giving effect of the equity infusion and resulting repayment of debt, we have $27.2 million of borrowing capacity under our amended Credit Facility. As a result, we believe we have and will continue to have sufficient liquidity to operate our business as the Second Amendment provides us with more favorable financial covenants than were provided previously and we believe these more favorable terms will allow us to operate our business and continue to meet our commitments.

Private Placement of Series A Convertible Preferred Units

        On April 12, 2013, to satisfy our requirements under our amended Credit Facility as discussed above, we entered into a Series A Convertible Preferred Unit Purchase Agreement with Southcross Energy LLC, pursuant to which we issued and sold 1,466,325 Series A Convertible Preferred Units (the "Series A Preferred Units") and agreed to sell, by June 30, 2013, an additional 248,675 Series A Preferred Units to Southcross Energy LLC for a cash purchase price of $22.86 per Series A Preferred Unit in a privately negotiated transaction (the "Private Placement").

        The Private Placement resulted in proceeds to us of $33.5 million. We also received a $0.7 million capital contribution from our General Partner to maintain its 2.0% general partner interest in us. When we sell to Southcross Energy LLC the additional 248,675 Series A Preferred Units for $5.7 million, our General Partner will make an additional capital contribution to us of $0.1 million.

        The total capital infusion to the Partnership of $40.0 million, from all sales of Series A Preferred Units and General Partner capital contributions were and will be used to reduce borrowings under our amended Credit Facility providing us with additional borrowing capacity For a complete description, see Part II, Item 8, "Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 6—Long-Term Debt and Note 14—Partners' Capital".

Contractual Obligations

        The following table summarizes our contractual obligations as of December 31, 2012 (in thousands):

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

Long-term debt:

                                

Principal(1)

   $ 191,000   $ —   $ —   $ 191,000   $ —  

Interest(2)

     37,094     7,545     15,089     14,460     —  

Vehicle fleet lease

     1,098     445     653     —     —  

Office lease

     1,382     401     981     —     —  
                       

Total

   $ 230,574   $ 8,391   $ 16,723   $ 205,460   $ —  
                       
(1)
Contractual obligations related to long-term debt assume $191.0 million outstanding as of December 31, 2012 is paid off at maturity in November 2017.

(2)
Interest is estimated at the weighted average interest rate for the year ended December 31, 2012 of 3.95% for periods through November 2017.

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Critical Accounting Policies and Estimates

        In our financial reporting process, we employ methods, estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of our financial statements. These methods, estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates if the underlying assumptions prove to be incorrect. The following describes the estimation risk currently underlying our most significant financial statement items:

Revenue Recognition Policies and Use of Estimates for Revenues and Expenses

        In general, we recognize revenue from customers when all of the following criteria are met:

        We record revenue for natural gas and NGL sales and transportation services over the period in which they are earned (i.e., either physical delivery of product has taken place or the services designated in the contract have been performed). While we make every effort to record actual volume and price data, there may be times where we need to use estimates for certain revenues and expenses. If the assumptions underlying our estimates prove to be substantially incorrect, it could result in material adjustments in results of operation.

Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment

        In general, depreciation is the systematic and rational allocation of an asset's cost, less its residual value (if any), to the periods it benefits. The majority of our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of an asset. Our estimate of depreciation expense incorporates management assumptions regarding the useful economic lives and residual values of our assets. We believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation amounts prospectively. Examples of such circumstances include:

Measuring Recoverability of Long-Lived Assets

        Long-lived assets such as property, plant and equipment are reviewed for impairment whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Examples of such events or changes might be production declines that are not replaced by new discoveries or long-term decreases in the demand or price of natural gas and NGLs. Long-lived assets with carrying values that are not expected to be recovered through forecast future cash flows are written-down to their estimated fair values. We evaluate the asset for recoverability by estimating the undiscounted future cash flows expected to be derived from operating the asset as a going concern. We determine the fair value of the asset by using our weighted average cost of capital to discount the

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present value of the future cash flows. The carrying value of a long-lived asset is not recoverable if it exceeds the present value of the estimated future cash flows expected to result from the use and eventual disposition of the asset. An impairment charge will be recorded to reduce the carrying amount to its estimated fair value.

New Accounting Pronouncements

        For a complete description of new accounting pronouncements, see Part II, Item 8. "Financial Statements and Supplementary Data—Notes to Financial Statements—Note 2—Basis of Presentation and Summary of Significant Accounting Policies".

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk.

        We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate. Both profitability and cash flow are affected by volatility in the prices of these commodities. Natural gas and NGL prices are impacted by changes in the supply and demand for natural gas and NGLs, as well as market uncertainty. Adverse effects on cash flow from increases or reductions in natural gas and NGL product prices could adversely affect our ability to make distributions to unitholders. We manage this commodity price exposure through an integrated strategy that includes management of the commercial terms of our contract portfolio by entering into fixed-fee-based or fixed-spread arrangements whenever possible and the use of swing swaps. Swing swaps are generally short term in nature (one month) and are usually entered into to protect against changes in the volume of daily versus first-of-month index priced gas supplies or markets. We have not entered into any long-term derivative contracts to manage exposure to commodity price risk. Natural gas and NGL prices, however, also can affect profitability indirectly by influencing the level of drilling activity in our areas of operation. We are a net seller of NGLs and, as such, financial results also are exposed to fluctuations in NGL price levels.

        A hypothetical increase or decrease in commodity prices by 1.0% would have changed our gross operating margin by $0.1 million and $0.3 million for the years ended December 31, 2012 and 2011, respectively.

Interest Rate Risk

        We have exposure to changes in interest rates on indebtedness. In March 2012, our Predecessor entered into an interest rate swap contract for $150.0 million notional amount of debt. The contract, which was transferred to the Partnership in conjunction with the IPO, effectively caps the Partnership's LIBOR based interest rate exposure on $150.0 million of debt at 0.54% through June 30, 2014.

        The credit markets have recently experienced historical lows in interest rates. As the overall economy strengthens, it is possible that monetary policy will tighten, resulting in higher interest rates. Interest rates on floating rate credit facilities and future debt offerings could be higher than current levels, causing the Partnership's financing costs to increase accordingly.

        A hypothetical increase or decrease in interest rates by 1.0% would have changed our interest expense by $1.2 million and $1.5 million for the years ended December 31, 2012 and 2011, respectively.

Risk Relating to NGLs

Recovery Commitments

        We have operational exposure under several gas supply and transportation agreements that contain fixed percentage NGL recovery obligations. To the extent that we do not produce, sell or re-deliver

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under transportation agreements at least as many gallons of NGL as required under those respective supply and transportation agreements, we are exposed to the equivalent replacement cost of the respective NGL products (e.g. ethane, propane) at NGL market prices net of contractual discounts, offset by the value of the unrecovered NGL products sold at methane natural gas prices. Similarly, to the extent that we produce, sell or re-deliver more gallons of NGL under transportation agreements than required under these agreements, we are able to sell the excess NGL products for our own account.

        A hypothetical increase or decrease in volumes recovered of 1.0% would have changed our gross operating margin by $0.9 million and $0.8 million for the years ended December 31, 2012 and 2011, respectively.

Pricing Differential

        We are exposed to the risk that we will be unable to sell NGLs at the expected differential to index prices necessary to preserve fixed-spread margins. To the extent that we do not produce marketable purity NGL products, due to operational disruptions or NGL market disruptions, we could realize lower than expected differentials to index prices.

        A hypothetical increase or decrease of $0.01 in our realized NGL gross operating margin spread per gallon would have changed our gross operating margin by $1.4 million and $0.8 million for the years ended December 31, 2012 and 2011, respectively.

Impact of Seasonality

        The results of operations were not affected materially by seasonality.

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Item 8.    Financial Statements and Supplementary Data


SOUTHCROSS ENERGY PARTNERS, L.P.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 
   Page  

Report of Independent Registered Public Accounting Firm

     85  

Consolidated Balance Sheets as of December 31, 2012 and 2011

    
86		  

Consolidated Statements of Operations for the Years Ended December 31, 2012, 2011 and 2010

    
87		  

Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2012, 2011, and 2010

    
88		  

Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010

    
89		  

Consolidated Statements of Changes in Partners' Capital and Members' Equity for the Years Ended December 31, 2012, 2011 and 2010

    
90		  

Notes to Consolidated Financial Statements

    
91		  

Supplemental Financial Information

        

Supplemental Selected Quarterly Financial Information (Unaudited)

    
124		  

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Southcross Energy Partners GP, LLC and the Unitholders of Southcross Energy Partners, L.P.

Dallas, Texas

        We have audited the accompanying consolidated balance sheets of Southcross Energy Partners, L.P., and subsidiaries (the "Partnership") as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), cash flows, and partners' capital and members' equity for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Southcross Energy Partners, L.P. and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Dallas, Texas

April 15, 2013

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SOUTHCROSS ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands, except for unit data)

 
   December 31,
2012 		  December 31,
2011 		 

ASSETS

              

Current assets:

              

Cash and cash equivalents

   $ 7,490   $ 1,412  

Trade accounts receivable

     50,994     41,234  

Prepaid expenses

     1,762     950  

Other current assets

     1,001     561  
           

Total current assets

     61,247     44,157  

Property, plant and equipment, net

    
550,603		    
369,861		  

Intangible assets, net

     1,624     1,681  

Other assets

     5,131     4,686  
           

Total assets

   $ 618,605   $ 420,385  
           

LIABILITIES, PREFERRED UNITS, PARTNERS' CAPITAL AND MEMBERS' EQUITY

              

Current liabilities:

              

Accounts payable and accrued liabilities

   $ 96,801   $ 50,439  

Current maturities of long-term debt

     —     17,490  

Other current liabilities

     3,586     5,007  
           

Total current liabilities

     100,387     72,936  

Long-term debt

    
191,000		    
190,790		  

Other non-current liabilities

     751     21  
           

Total liabilities

     292,138     263,747  
           

Commitments and contingencies (Note 11)

              

Preferred units of Southcross Energy LLC:

              

Redeemable preferred units

     —     16,554  

Series B redeemable preferred units

     —     —  

Series C redeemable preferred units

     —     —  

Preferred units

     —     150,249  

Partners' capital and members' equity:

              

Partners' capital:

              

Common units—(12,213,713 units issued and outstanding as of December 31, 2012)

     194,365     —  

Subordinated units—(12,213,713 units issued and outstanding as of December 31, 2012)

     125,951     —  

General Partner interest

     6,628     —  

Accumulated other comprehensive loss

     (477 )   —  

Members' equity of Southcross Energy LLC:

              

Common equity—Class A (1,415,729 units issued and outstanding as of December 31, 2011)

     —     1,416  

Common equity—Class B (57,279 units issued and outstanding as of December 31, 2011)

     —     57  

Accumulated deficit

     —     (11,638 )
           

Total partners' capital and members' equity

     326,467     (10,165 )
           

Total liabilities, preferred units, partners' capital and members' equity

   $ 618,605   $ 420,385  
           

   

See accompanying notes to these consolidated financial statements.

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SOUTHCROSS ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except for unit and per unit data)

 
   Year ended December 31,  
 
   2012   2011   2010  

Revenues

   $ 496,129   $ 523,149   $ 498,747  

Expenses:

                    

Cost of natural gas and liquids sold

     424,489     460,580     439,431  

Operations and maintenance

     35,532     24,707     21,106  

Depreciation and amortization

     18,977     12,345     10,987  

General and administrative

     13,842     9,129     7,490  
               

Total expenses

     492,840     506,761     479,014  
               

Income from operations

     3,289     16,388     19,733  

Loss on extinguishment of debt

     (1,764 )   (3,240 )   —  

Interest expense

     (5,767 )   (5,348 )   (10,013 )
               

(Loss) income before income tax expense

     (4,242 )   7,800     9,720  

Income tax expense

     (246 )   (261 )   (1 )
               

Net (loss) income

   $ (4,488 ) $ 7,539   $ 9,719  
               

Less:

                    

Net loss from January 1, 2012 through November 6, 2012

     (260 )            
                   

Net loss attributable to partners

   $ (4,228 )            

General partner's interest

    
(85
)		            
                   

Limited partners' interest

   $ (4,143 )            
                   

Net loss from January 1, 2012 through November 6, 2012

   $ (260 )            

Less deemed dividend on:

                    

Redeemable preferred units

     (2,693 )   (1,553 )   —  

Series B redeemable preferred units

     (4,696 )   —     —  

Series C redeemable preferred units

     (2,012 )   —     —  

Preferred units

     (13,249 )   (14,131 )   (12,802 )
               

Net loss attributable to Southcross Energy LLC common unitholders

   $ (22,910 ) $ (8,145 ) $ (3,083 )
               

Basic and diluted earnings per unit

                    

Net loss allocated to limited partner common units (from November 7, 2012 through December 31, 2012)

   $ (2,072 )            

Weighted average number of limited partner common units outstanding

     12,213,713              

Loss per common unit

   $ (0.17 )            

Net loss allocated to limited partner subordinated units

  
$
(2,072
)		            

Weighted average number of limited partner subordinated units outstanding

     12,213,713              

Loss per subordinated unit

   $ (0.17 )            

Net loss allocated to Southcross Energy LLC common units

  
$
(22,910
)
$
(8,145
)
$
(3,083
)

Weighted average number of Southcross Energy LLC common units outstanding

     1,198,429     1,197,876     1,197,257  

Loss per Southcross Energy LLC common unit

   $ (19.12 ) $ (6.79 ) $ (2.57 )

   

See accompanying notes to these consolidated financial statements.

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SOUTHCROSS ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

 
   Year ended December 31,  
 
   2012   2011   2010  

Net (loss) income

   $ (4,488 ) $ 7,539   $ 9,719  

Other comprehensive loss

                    

Hedging losses reclassified to earnings

     268     —     —  

Adjustment in fair value of derivatives

     (745 )   —     —  
               

Total other comprehensive loss

     (477 )   —     —  
               

Comprehensive income (loss)

   $ (4,965 ) $ 7,539   $ 9,719  
               

   

See accompanying notes to these consolidated financial statements.

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SOUTHCROSS ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

 
   Year ended December 31,  
 
   2012   2011   2010  

Cash flows from operating activities:

                    

Net (loss) income

   $ (4,488 ) $ 7,539   $ 9,719  

Adjustments to reconcile net (loss) income to net cash provided by operating activities:

                    

Depreciation and amortization

     18,977     12,345     10,987  

Unit-based compensation

     630     —     —  

Loss on extinguishment of debt

     1,764     3,240     —  

Deferred financing costs amortization

     1,183     882     2,158  

Gain on sale of property, plant and equipment

     —     (522 )   (13 )

Unrealized derivatives loss

     141     21     —  

Changes in operating assets and liabilities:

                    

Trade accounts receivable

     (9,760 )   (2,806 )   4,897  

Prepaid expenses and other

     (1,246 )   (497 )   560  

Other non-current assets

     1,786     (2,155 )   158  

Accounts payable and accrued expenses

     16,517     2,759     (3,836 )

Other liabilities

     (1,181 )   (799 )   863  
               

Net cash provided by operating activities

     24,323     20,007     25,493  
               

Cash flows from investing activities:

                    

Capital expenditures

     (169,816 )   (123,347 )   (5,245 )

Acquisition of Enterprise Alabama Intrastate, LLC

     —     (21,777 )   —  

Proceeds from sale of property, plant and equipment

     —     522     14  
               

Net cash used in investing activities

     (169,816 )   (144,602 )   (5,231 )
               

Cash flows from financing activities:

                    

Proceeds from issuance of common units, net

     187,764     —     —  

Borrowings under our credit agreements

     297,500     229,400     14,195  

Repayments of our credit agreements

     (314,780 )   (136,119 )   (19,144 )

Financing costs

     (5,178 )   (2,710 )   (752 )

Repayment of equity note

     —     113     38  

Repurchase and retirement of Southcross Energy LLC common units

     (15,300 )   —     —  

Proceeds from issuance of redeemable preferred units

     —     15,000     —  

Proceeds from issuance of Series B redeemable preferred units

     42,800     —     —  

Proceeds from issuance of Series C redeemable preferred units

     30,000     —     —  

Distribution to Southcross Energy LLC

     (46,030 )   —     —  

Purchase and retirement of Partnership common units

     (25,205 )   —     —  
               

Net cash provided by (used in) financing activities

     151,571     105,684     (5,663 )
               

Net increase (decrease) in cash and cash equivalents

     6,078     (18,911 )   14,599  

Cash and cash equivalents—Beginning of period

     1,412     20,323     5,724  
               

Cash and cash equivalents—End of period

   $ 7,490   $ 1,412   $ 20,323  
               

Cash paid for interest

   $ 10,552   $ 7,994   $ 6,241  

Cash paid for taxes

   $ 315   $ 272   $ 133  

Non-cash transactions:

                    

Accounts payable related to capital expenditures

   $ 40,707   $ 10,862   $ 632  

   

See accompanying notes to these consolidated financial statements.

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SOUTHCROSS ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL AND MEMBERS' EQUITY

(In thousands)

 
   Partners' Capital   Southcross Energy LLC
Members' Equity 		   
  
 
   Limited Partners    
   Accumulated
Other
Comprehensive
Loss 		   
    
    
    
  
 
   General
Partner 		  Common
Class A 		  Common
Class B 		  Accumulated
Deficit 		   
  
 
   Common   Subordinated   Total  

BALANCE—December 31, 2009

   $ —   $ —   $ —   $ —   $ 1,414   $ 57   $ (410 ) $ 1,061  

Receipt of payment from unit note holder

     —     —     —     —     1     —     —     1  

Net income

     —     —     —     —     —     —     9,719     9,719  

Deemed dividend on preferred units

     —     —     —     —     —     —     (12,802 )   (12,802 )
                                   

BALANCE—December 31, 2010

   $ —   $ —   $ —   $ —   $ 1,415   $ 57   $ (3,493 ) $ (2,021 )
                                   

Receipt of payment from unit note holder

     —     —     —     —     1     —     —     1  

Net income

     —     —     —     —     —     —     7,539     7,539  

Deemed dividend on:

     —     —     —     —     —     —     —     —  

Redeemable Preferred Units

     —     —     —     —     —     —     (1,553 )   (1,553 )

Preferred Units

     —     —     —     —     —     —     (14,131 )   (14,131 )
                                   

BALANCE—December 31, 2011

   $ —   $ —   $ —   $ —   $ 1,416   $ 57   $ (11,638 ) $ (10,165 )
                                   

Net loss attributable to the period January 1, 2012 through November 6, 2012

     —     —     —     —     —     —     (260 )   (260 )

Deemed dividend on:

                                                  

Redeemable Preferred Units

     —     —     —     —     —     —     (2,693 )   (2,693 )

Series B Redeemable Preferred Units

     —     —     —     —     —     —     (4,696 )   (4,696 )

Series C Redeemable Preferred Units

     —     —     —     —     —     —     (2,012 )   (2,012 )

Preferred Units

     —     —     —     —     —     —     (13,249 )   (13,249 )

Repurchase and retirement of Southcross Energy LLC common units

     —     —     —     —     (131 )   —     (15,169 )   (15,300 )

Contribution by Southcross Energy LLC

     43,274     164,464     6,713     —     (1,285 )   (57 )   49,717     262,826  

Issuance of common units, net

     187,764     —     —     —     —     —     —     187,764  

Distributions to Southcross Energy LLC

     (9,589 )   (36,441 )   —     —     —     —     —     (46,030 )

Purchase and retirement of Partnership common units

     (25,205 )   —     —     —     —     —     —     (25,205 )

Unit-based compensation

     192     —     —     —     —     —     —     192  

Net loss attributable to the period November 7, 2012 through December 31, 2012

     (2,071 )   (2,072 )   (85 )   —     —     —     —     (4,228 )

Net effect of cash flow hedges

     —     —     —     (477 )   —     —     —     (477 )
                                   

BALANCE—December 31, 2012

   $ 194,365   $ 125,951   $ 6,628   $ (477 ) $ —   $ —   $ —   $ 326,467  
                                   

   

See accompanying notes to these consolidated financial statements.

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SOUTHCROSS ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND DESCRIPTION OF BUSINESS

Organization

        Southcross Energy Partners, L.P. (the "Partnership," "Southcross," the "Company," "we," "our," or "us") is a Delaware limited partnership formed in April 2012 for the purpose of acquiring and operating the midstream assets of Southcross Energy LLC, a Delaware limited liability company, and its subsidiaries. Southcross Energy LLC was formed in 2009 for the purpose of acquiring and operating midstream assets in anticipation of an initial public offering of the Partnership's units. Through a series of transactions described in Note 14, Southcross Energy LLC contributed all of its operating subsidiaries (its net assets on a historical cost basis) to the Partnership, excluding certain liabilities and all preferred units, and became the holding company of the Partnership. Southcross Energy LLC holds all of the equity interests in Southcross Energy Partners GP, LLC ("General Partner"), as well as all subordinated units and a portion of the common units of the Partnership. Southcross Energy LLC and its subsidiaries are controlled through investment funds and entities associated with Charlesbank Capital Partners, LLC ("Charlesbank").

Liquidity Considerations

        During the fourth quarter 2012 and into the first quarter 2013 we encountered operational challenges caused by several events:

        These items impacted our operating results adversely and as a result of this negative impact we believed it was unlikely that we would be in compliance with our financial covenants calculated for the quarter ending March 31, 2013, such that we negotiated with our lenders and secured more favorable financial covenants associated with our Senior Secured Credit Facility ("Credit Facility").

        On March 27, 2013, we entered into the first amendment (the "First Amendment") to the Credit Facility. As a result of the First Amendment, our letters of credit sublimit was reduced from $75.0 million to $31.5 million and our available credit was reduced from $350.0 million to $250.0 million, plus the sum of any amounts placed on deposit in a collateral account of our General Partner (the "Collateral Account"), plus letters of credit outstanding. Our General Partner deposited $10.0 million into the Collateral Account as required under the First Amendment. Pursuant to the First Amendment, we are allowed to pay our quarterly cash distribution of available cash for the first quarter 2013 in an amount not to exceed the amount then on deposit in the Collateral Account. Because the First Amendment did not modify our requirement to meet the financial covenants under the Credit Facility beginning March 31, 2013 we further amended our Credit Facility as discussed below.

        As discussed in Note 6, on April 12, 2013 we entered into the limited waiver and second amendment (the "Second Amendment") to the Credit Facility which waived our defaults relating to financial covenants for the period ending March 31, 2013 and provided more favorable financial covenants until we give notice under the amended Credit Facility that we have achieved a Target

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SOUTHCROSS ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. ORGANIZATION AND DESCRIPTION OF BUSINESS (Continued)

Leverage Ratio (as defined in the Second Amendment) of 4.25 to 1.00 for one quarter or 4.50 to 1.00 for two consecutive quarters, calculated excluding the benefit of cash on deposit in the Collateral Account and any equity cure amounts (the "Target Leverage Test"). Our available credit continues to be subject to the availability limits described in the First Amendment.

        As a condition to the Second Amendment, Southcross Energy LLC and our General Partner deposited into the Collateral Account a total of $34.2 million, including the $10.0 million previously deposited under the First Amendment. Additionally, Southcross Energy LLC and our General Partner agreed to deposit into the Collateral Account the proceeds they receive from cash distributions on units in us that are attributable to the quarters ending March 31, 2013, June 30, 2013, September 30, 2013 and December 31, 2013.

        The Second Amendment provides for, among other things, the following:

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1. ORGANIZATION AND DESCRIPTION OF BUSINESS (Continued)

        If, for the calendar quarters ending on or before December 31, 2013, we fail to comply with the financial covenants of the amended Credit Facility ("Financial Covenant Default") we have the right (which cannot be exercised more than two times) to cure such Financial Covenant Default by having Southcross Energy LLC and/or our General Partner deposit into the Collateral Account the amount required by the Second Amendment to cure such Financial Covenant Default.

        As of April 12, 2013, after giving effect of the equity infusion and resulting repayment of debt, we have $27.2 million of borrowing capacity under our amended Credit Facility. As a result, we believe we have and will continue to have sufficient liquidity to operate our business as the Second Amendment provides us with more favorable financial covenants than were provided previously, and we believe these more favorable terms will allow us to operate our business and continue to meet our commitments.

Private Placement of Series A Convertible Preferred Units

        As further discussed in Note 14, on April 12, 2013, to satisfy our requirements under our amended Credit Facility as discussed above, we entered into a Series A Convertible Preferred Unit Purchase Agreement with Southcross Energy LLC, pursuant to which we issued and sold 1,466,325 Series A Convertible Preferred Units (the "Series A Preferred Units") and agreed to sell, by June 30, 2013, an additional 248,675 Series A Preferred Units to Southcross Energy LLC for a cash purchase price of $22.86 per Series A Preferred Unit in a privately negotiated transaction (the "Private Placement").

        The Private Placement resulted in proceeds to us of $33.5 million. We also received a $0.7 million capital contribution from our General Partner to maintain its 2.0% general partner interest in us. When we sell to Southcross Energy LLC the additional 248,675 Series A Preferred Units for $5.7 million, our General Partner will make an additional capital contribution to us of $0.1 million.

        The total capital infusion to the Partnership of $40.0 million, from all sales of Series A Preferred Units and General Partner capital contributions were and will be used to reduce borrowings under our amended Credit Facility providing us with additional borrowing capacity (See Note 6).

Initial Public Offering

        On November 7, 2012, Southcross completed its initial public offering (the "IPO") and after the completion of the IPO and full exercise of the underwriters' over-allotment option, Southcross Energy LLC's direct and indirect equity ownership in the Partnership was 58.5%. As the series of transactions described in Note 14 relate to entities under common control, these consolidated financial statements reflect the assets, liabilities, results of operations and cash flows of the Partnership beginning November 7, 2012 and Southcross Energy LLC as of and for the periods ending prior to November 7, 2012. There was no change in the basis of accounting as a result of the IPO or the transactions described in Note 14. Unless the context states otherwise, references to "we," "us," "our," "Partnership," "Company" or like terms refer to Southcross Energy Partners, L.P. and its subsidiaries.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. ORGANIZATION AND DESCRIPTION OF BUSINESS (Continued)

        The following table depicts the ownership structure of the Partnership as of December 31, 2012:

Description
  Percentage
ownership 		 

Public common units

     41.5 %

Southcross Energy LLC:

        

Common units

     7.5 %

Subordinated units

     49.0 %

General partner units(1)

     2.0 %
       

Total

    100.0 %
       
(1)
General partner units are owned by Southcross Energy Partners GP, LLC which is 100% owned by Southcross Energy LLC.

Description of Business

        The Partnership is a midstream natural gas company with operations in South Texas, Mississippi and Alabama. We operate as one reportable segment and provide, through our subsidiaries, natural gas gathering, processing, treating, compression and transportation services and natural gas liquids ("NGL") fractionation and transportation services for our producer customers, and source, purchase, transport and sell natural gas and NGLs to power generation, industrial and utility customers.

2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

        The accompanying consolidated financial statements and related notes present the consolidated balance sheets as of December 31, 2012 and 2011 and the consolidated statements of operations, consolidated statements of comprehensive income, consolidated statements of cash flows and changes in partners' capital and members' equity for the periods ended December 31, 2012, 2011 and 2010. As a result of our IPO, there was no change in the accounting basis of the contributed net assets of Southcross Energy LLC. Information included in these financial statements and related notes are presented as if the Partnership and Southcross Energy LLC were the same entity, except with respect to associated changes in capitalization as described in Note 14.

        The accompanying consolidated financial statements were prepared in accordance with accounting principles generally accepted in the U.S. ("GAAP") and in accordance with the rules and regulations of the U.S. Securities and Exchange Commission ("SEC"). Our consolidated financial statements include the accounts of Southcross and its 100% owned subsidiaries. We eliminate all intercompany balances and transactions in preparing consolidated financial statements. In management's opinion, all necessary adjustments to present fairly our results of operations, financial position and cash flows for the relevant periods have been made and all such adjustments are of a normal and recurring nature.

Principles of Consolidation

        We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to

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2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. We do not have ownership in any variable interest entities.

Use of Estimates

        The preparation of the consolidated financial statements requires management to make estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and disclosure in these consolidated financial statements. Actual results may differ from those estimates.

Cash and Cash Equivalents

        Cash and cash equivalents include all cash balances and investments in highly liquid financial instruments purchased with original maturities of three months or less. Our cash equivalents consist primarily of temporary investments of cash in short-term money market instruments.

Allowance for Doubtful Accounts

        In evaluating the collectability of its accounts receivable, the Partnership performs ongoing credit evaluations of its customers and adjusts payment terms based upon payment history and each customer's current creditworthiness, as determined by the Partnership's review of such customer's credit information. The Partnership extends credit on an unsecured basis to many of its customers. At December 31, 2012 and 2011, we have recorded no allowance for uncollectable accounts receivable.

Long-Lived Assets

        Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead and interest. Costs associated with obtaining rights of way agreements and easements to facilitate the building and maintenance of new pipelines are capitalized and we depreciate such costs over the life of the associated pipeline. We capitalize major units of property replacements or improvements and expense minor items. We use the straight-line method of depreciation to depreciate property, plant and equipment over the estimated useful lives of the assets.

        When we retire property, plant and equipment, we charge accumulated depreciation for the original cost of the assets in addition to the cost to remove, sell or dispose of the assets, less their salvage value. We include gains or losses on dispositions of assets in operations and maintenance expense in our consolidated statements of income.

        Our intangible assets consist of acquired long-term supply and gas gathering contracts. We amortize these contracts on a straight-line basis over the 30 year expected useful lives of the contracts.

        We evaluate our long-lived assets, which include finite-lived intangible assets, for impairment when events or circumstances indicate that their carrying values may not be recovered. These events include, but are not limited to, market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, we evaluate

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2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

the recoverability of our carrying value based on the long-lived asset's ability to generate future cash flows on an undiscounted basis. If the undiscounted cash flows are not sufficient to recover the long-lived asset's carrying value, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying values of the asset downward, if necessary, to their estimated fair value. Our fair value estimates are generally based on assumptions market participants would use, including market data obtained through the sales process or an analysis of expected discounted cash flows. At December 31, 2012 and 2011, we have recorded no impairment of long-lived assets.

Other Assets

        Other assets primarily include financing costs incurred in connection with borrowings of long-term debt that are deferred and charged to interest expense over the term of the related debt.

Asset Retirement Obligations

        The Partnership evaluates whether any future asset retirement obligations ("AROs") exist and estimates the costs for such AROs for certain future events. We do not have sufficient information to reasonably estimate any future AROs, because the Partnership has no intention of discontinuing the use of any significant assets or does not have a legal obligation to do so. We are not aware of any AROs as of December 31, 2012 and 2011. An ARO will be recorded in the periods where management can reasonably determine the settlement dates or the period in which the expense is incurred.

Environmental Costs and Other Contingencies

        We recognize liabilities for environmental and other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and no specific amount in that range is more likely than any other, the low end of the range is accrued. We are not aware of any liabilities for environmental or other contingencies as of December 31, 2012 and 2011.

Revenue Recognition

        The Partnership records revenue and related costs for natural gas and NGL sales and transportation services in the period in which they are earned. Revenue primarily consists of the sale of NGLs along with fees earned from its gathering and processing operations. Under certain agreements, the Partnership purchases natural gas from producers at receipt points on the pipeline systems and then sells the natural gas, or produced NGLs, if any, at delivery points on its systems. The Partnership records revenue and cost of product sold on a gross basis for these transactions where the Partnership acts as principal and takes title to the natural gas or NGLs. The Partnership also has contracts where it does not take title to the natural gas and charges fees for providing services such as gathering, treating or transportation and records these fees separately in revenues as transportation, gathering and processing fees. The Partnership recognizes revenue when all of the following criteria are met: persuasive evidence of an exchange arrangement exists; delivery has occurred or services have been rendered; the price is fixed or determinable; and, collectability is reasonably assured.

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2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

        The Partnership derives revenue in its business from the following types of arrangements:

Fair Value of Financial Instruments

        The Partnership uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources. Unobservable inputs reflect the Partnership's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further segregated pursuant the following hierarchy:

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2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

        The Partnership's financial instruments include cash and cash equivalents, accounts receivable, accounts payable, fixed rate debt, variable rate debt and swap contracts based upon interest rate and natural gas price indices. The Partnership does not hold or issue financial instruments or derivative financial instruments for trading purposes.

Derivative Instruments

        In its normal course of business, the Partnership enters into month-ahead swap contracts in order to hedge economically its exposure to certain intra-month natural gas index pricing risk. The Partnership manages its interest rate risk through interest rate swaps.

        The Partnership measures the derivatives at fair value on a recurring basis using the best information and techniques available, which are primarily Level 2 inputs as defined in the fair value hierarchy (See Note 5).

Comprehensive Income

        To the extent that the Partnership's cash flow hedge is effective, unrealized gains and losses will be recorded as accumulated other comprehensive income and will be transferred to income and recognized as interest expense in the period the underlying hedged transactions (interest payments) are recorded. Any hedge ineffectiveness will be recognized in interest expense immediately.

Unit-Based Compensation

        Unit-based awards which settle in common units are classified as equity and are recognized in the financial statements at their grant date fair value. Unit-based awards which settle in cash are classified as liabilities and remeasured at every balance sheet date through settlement, such that the vested portion of the liability is adjusted to reflect its revised fair value through compensation expense. Compensation expense associated with unit-based awards, adjusted for forfeitures, is recognized within general and administrative expenses on the Partnership's consolidated statements of operations from the date of the grant over the vesting period.

Income Taxes

        No provision for federal or state income taxes is included in our results of operations as such income is taxable directly to the partners of the Partnership. Each partner is responsible for its share of federal and state income tax. Net earnings for financial statement purposes may differ significantly from taxable income reportable to each partner as a result of differences between the tax basis and financial reporting basis of assets and liabilities.

        We are responsible for our portion of the Texas margin tax that is included in Southcross Energy LLC's consolidated Texas franchise tax return. Our current tax liability will be assessed based on the gross revenue apportioned to Texas. The margin tax qualifies as an income tax under GAAP, which requires us to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Uncertain Tax Positions

        We evaluate the uncertainty in tax positions taken or expected to be taken in the course of preparing our consolidated financial statements to determine whether the tax positions are more likely than not of being sustained by the applicable tax authority. Tax positions with respect to tax at the partnership level deemed not to meet the more likely than not threshold would be recorded as a tax benefit or expense in the current year.

Earnings per Unit

        Net income (loss) per unit is calculated under the two-class method of computing earnings per unit when participating or multiple classes of securities exist. Under this method, undistributed earnings or losses for a period are allocated based on the contractual rights of each security to share in those earnings as if all of the earnings for the period had been distributed.

        Basic net income (loss) per unit excludes dilution and is computed by dividing net income (loss) attributable to common limited partner units by the weighted average number of common limited partner units outstanding during the period. Dilutive net income (loss) per unit reflects potential dilution from the potential issuance of common limited partner units. Dilutive net income (loss) per unit is computed by dividing net income (loss) attributable to common limited partner units by the weighted average number of common limited partner units outstanding during the period increased by the number of additional common limited partner units that would have been outstanding if the dilutive potential common limited partner units had been issued.

New Accounting Pronouncements

        Accounting standard-setting organizations frequently issue new or revised accounting rules. We regularly review all new pronouncements to determine their impact, if any, on our financial statements.

        In June 2011, the Financial Accounting Standards Board ("FASB") issued an accounting standards update on "Presentation of Comprehensive Income". This update amended existing guidance by allowing only two options for presenting the components of net income and other comprehensive income: (1) in a single continuous financial statement, statement of comprehensive income or (2) in two separate but consecutive financial statements, consisting of an income statement followed by a separate statement of other comprehensive income.

        The Partnership adopted this standard effective January 1, 2012, which changed presentation of certain financial statements, but did not have any material or other impact on our financial statements.

        In February 2013, the FASB issued an accounting standards update on "Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income." This update requires that we report reclassifications out of accumulated other comprehensive income and their effect on net income by component or financial statement line effective for our quarterly filing for the three months ended March 31, 2013. We do not expect this to impact our consolidated financial results, as the only required change is the format of our presentation.

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3. ACQUISITIONS

Enterprise Alabama Intrastate, LLC

        Southcross Energy LLC acquired Enterprise Alabama Intrastate, LLC ("EAI") from Enterprise GTM Holdings L.P. for $21.8 million on September 1, 2011. EAI owned 388 miles of 2 to 16 inch natural gas pipeline assets located in northwest and central Alabama, and provided gathering, transportation and compression services and engaged in the purchase and sale of natural gas. EAI's identifiable assets acquired and liabilities assumed were recorded based upon the fair values determined on the date of acquisition.

        The fair values of the EAI property, plant and equipment were determined based upon assumptions related to expected future cash flows, discount rates and asset lives using currently available information. Southcross Energy LLC utilized a mix of the cost, income and market approaches to determine the estimated fair values of such assets. The fair value measurements and models were classified as non-recurring Level 3 measurements.

        Southcross Energy LLC completed its assessment of the fair value of the assets acquired and liabilities assumed as of March 31, 2012 and determined the consideration given was equal to the fair value of net assets acquired. As a result, no goodwill was recorded.

        The reconciliation of the fair value of the assets acquired and liabilities assumed related to the EAI purchase price was as follows (in thousands):

Purchase Price—Cash

    21,777  

Current assets

  
$
3,374		  

Property, plant, and equipment

     19,300  

Intangible assets

     1,700  
       

Total assets acquired

     24,374  

Current liabilities

    
2,597		  
       

Total liabilities assumed

     2,597  
       

Net identifiable assets acquired

  $ 21,777  
       

        Southcross Energy LLC attributed $1.7 million to intangible assets associated with long-term supply and gathering contracts assumed in the acquisition (See Note 8).

        In the third quarter of 2011, Southcross Energy LLC expensed $0.2 million of transaction costs associated with the acquisition of EAI. These costs are reported within general and administrative expenses.

        The following unaudited pro forma financial information of the Partnership assumes that the EAI acquisition occurred on January 1, 2010 and includes adjustments for income from operations, including

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3. ACQUISITIONS (Continued)

depreciation and amortization, as well as the effects of financing the acquisition (in thousands, except unit information):

 
   Year Ended
December 31, 2011 		  Year Ended
December 31, 2010 		 
 
   Southcross   Combined   Southcross   Combined  

Total revenue

   $ 523,149   $ 548,152   $ 498,747   $ 541,618  

Net income

     7,539     7,789     9,719     8,891  

Net loss attributable to common unitholders

     (8,145 )   (7,895 )   (3,083 )   (3,911 )

Net loss per unit—(basic and diluted)

     (6.79 )   (6.59 )   (2.57 )   (3.27 )

        The unaudited pro forma information is not necessarily indicative of what the Partnership's results of operations would have been if the transaction had occurred on that date, or what the financial position or results from operations will be for any future periods. For the period from September 1, 2011 through December 31, 2011, EAI contributed $11.0 million in revenues and $0.8 million in net income to Southcross Energy LLC's results of operations.

4. NET INCOME PER LIMITED PARTNER UNIT AND DISTRIBUTIONS

Earnings Per Unit of the Partnership

        The following is a reconciliation of net loss attributable to limited partners and the limited partner units used in the basic and diluted earnings per unit calculations for the year ended December 31, 2012. (in thousands, except per unit data)

Allocation of Net loss

 
   Year ended
December 31, 2012 		 

Net loss

   $ (4,488 )

Less:

        

Net loss from January 1, 2012 through November 6, 2012

     (260 )
       

Net loss attributable to partners

   $ (4,228 )
       

General partner's interest

  
$
(85
)

Limited partners' interest:

        

Common

   $ (2,072 )

Subordinated

   $ (2,072 )

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4. NET INCOME PER LIMITED PARTNER UNIT AND DISTRIBUTIONS (Continued)

Net Loss Per Limited Partners' Interest

Year ended December 31, 2012
  Common   Subordinated  

Interest in net loss

   $ (2,072 ) $ (2,072 )

Weighted-average units—basic

    
12,214		    
12,214		  

Effect of diluted units(1)

     —     —  
           

Weighted-average units—diluted

     12,214     12,214  
           

Basic earnings per unit:

              

Net loss per unit

   $ (0.17 ) $ (0.17 )

Diluted earnings per unit:

              

Net loss per unit

   $ (0.17 ) $ (0.17 )
(1)
Because we had a net loss for the year ended December 31, 2012, the weighted average units outstanding are the same for basic and diluted net loss per common unit. At December 31, 2012, the amount of unvested common units that were not included in the computation of diluted per unit amounts was 144,500.

Distributions

        Our First Amended and Restated Agreement of Limited Partnership ("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, as determined by our General Partner. 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 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.

        Our General Partner is currently entitled to 2% 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% 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% 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%, of the cash we distribute from operating surplus in excess of $0.46 per unit per quarter. The maximum distribution of 50% includes distributions paid to our General Partner on its 2% general partner interest and assumes that our General Partner maintains its general partner interest at 2%. The maximum distribution of 50% does not include any distributions that our General Partner may receive on any limited partner units that it owns.

        The Partnership declared its first distribution of $0.24 per common and subordinated unit which was attributable to the quarter ended December 31, 2012, and represented a pro-rated cash distribution

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4. NET INCOME PER LIMITED PARTNER UNIT AND DISTRIBUTIONS (Continued)

for the portion of the quarter following the closing of the Partnership's IPO on November 7, 2012. The distribution corresponds to the minimum quarterly distribution of $0.40 per unit or $1.60 on an annualized basis.

        The Partnership paid approximately $6 million on February 14, 2013 to unitholders of record on February 11, 2013 attributable to the quarter ended December 31, 2012 distribution.

Earnings Per Common Unit of Southcross Energy LLC

        A reconciliation of basic and diluted earnings per unit related to the Southcross Energy LLC common units is included in our consolidated statements of operations.

        Southcross Energy LLC calculated earnings per common unit by first deducting the amount of cumulative returns on both the Redeemable Preferred and Preferred units from net income (loss), and dividing this amount by the weighted average number of vested common units (including both the vested Class A common units and Class B units). For periods presented in which Southcross Energy LLC units were outstanding, no unvested common units were included in the computation of the diluted per unit amount because all would have been antidilutive to the net loss per common unit holder. The amount of unvested common units that were not included in the computation of diluted per unit amounts were 143,220 units, 274,762 units and 275,381 units for periods ended November 6, 2012, December 31, 2011 and 2010 respectively.

5. FINANCIAL INSTRUMENTS

Cash and Cash Equivalents, Accounts Receivable and Accounts Payable

        As of December 31, 2012 and 2011, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable represent fair values based on the short-term nature of these instruments.

Senior Secured Credit Facility ("Credit Facility")

        The fair value of our Credit Facility executed in 2012 approximates its carrying amount as of December 31, 2012 due primarily to the variable nature of the interest rate of the instrument and given the limited changes in the interest rate environment since its origination on November 7, 2012, which is considered a Level 2 fair value measurement.

Southcross Energy LLC Amended and Restated Credit Agreement, dated June 10, 2011 ("Credit Agreement")

        The fair value of our Credit Agreement approximates its carrying amount as of December 31, 2011 due primarily to the variable nature of the interest rate of the instrument, which is considered a Level 2 fair value measurement. In connection with the IPO, the Credit Agreement was assumed and repaid by the Partnership.

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5. FINANCIAL INSTRUMENTS (Continued)

Derivatives

Interest Rate Swaps

        The Partnership manages its interest rate risk through interest rate swaps. The current portion of the interest rate swap liability of $0.3 million was included within other current liabilities, and the non-current portion of the interest rate swap liability of $0.3 million was included within other non-current liabilities as of December 31, 2012. The interest rate cap liability was included within other non-current liabilities as of December 31, 2011.

        The fair value of the interest rate cap and interest rate swap liabilities were as follows (in thousands):

 
   Fair value measurement as of  
 
   December 31, 2012   December 31, 2011  
 
   Significant Other Observable Inputs (Level 2)  

Interest rate cap liability

   $ —   $ 21  

Interest rate swap liability

   $ 638   $ —  

        On February 17, 2011, the we entered into an interest rate cap contract with Wells Fargo, N.A., effective March 31, 2011, for $80.0 million in notional value. The contract effectively capped our LIBOR-based interest rate on that portion of debt on a sliding scale that started at 1.51% as of March 31, 2011 and increased to 4.57% at the end of the contract on June 30, 2014. The notional amount of debt specified in the cap contract declines over time so that the amount of debt covered equates to $65.0 million, $43.0 million and $23.0 million at December 31, 2011, 2012, and 2013, respectively. We did not designate the interest rate cap as a hedging instrument for accounting purposes and, thus, the realized and unrealized gains and losses were recognized in interest expense during the period. We defined this contract as a fair value hierarchy of Level 2.

        In March 2012, we terminated the interest rate cap and entered into an interest rate swap contract with Wells Fargo, N.A. The interest rate swap has a notional value of $150.0 million, and a maturity date of June 30, 2014. We receive a floating rate based upon one-month LIBOR and pay a fixed rate under the interest rate swap of 0.54%. We designated the interest rate swap as a cash flow hedge for accounting purposes and, thus, to the extent the cash flow hedge was effective, unrealized gains and losses were recorded to accumulated other comprehensive income/(loss) and recognized in interest expense as the underlying hedged transactions (interest payments) were recorded. Any hedge ineffectiveness is recognized in interest expense immediately. We did not have any hedge ineffectiveness during the year ended December 31, 2012. We defined this contract as a fair value hierarchy of Level 2.

        Based on current interest rates, the Partnership estimated that approximately $0.3 million of hedging losses related to the interest rate swap contract will be reclassified from accumulated other comprehensive income/(loss) into results of operations within the next 12 months.

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5. FINANCIAL INSTRUMENTS (Continued)

        The amounts recognized in interest expense associated with derivatives that are not designated as hedging instruments were as follows (in thousands):

 
   Year ended
December 31, 		 
 
   2012   2011   2010  

Unrealized loss on interest rate cap

   $ (141 ) $ (21 ) $ —  

Realized loss on interest rate cap

   $ (82 ) $ (147 )   —  

        The amounts recognized in interest expense associated with derivatives that are designated as hedging instruments were as follows (in thousands):

 
   Year ended
December 31, 		 
 
   2012   2011   2010  

(Loss) reclassified from accumulated other comprehensive loss

   $ (268 ) $ —   $ —  

        The change in value recognized in other comprehensive income/(loss) on the interest rate swap (effective portion) was as follows (in thousands):

 
   Year ended
December 31, 		 
 
   2012   2011   2010  

Change in value recognized in other comprehensive loss (effective portion)

   $ (745 ) $ —   $ —  

Commodity Swaps

        In its normal course of business, the Partnership periodically enters into month-ahead swap contracts to hedge its exposure to certain intra-month natural gas index pricing risk economically. There were no outstanding month-ahead swap contracts as of December 31, 2012 and total volume of month-ahead swap contracts outstanding as of December 31, 2011 was 372,000 MMBtu. The Partnership defines the contracts as Level 2, as the index price associated with such contracts was observable and tied to similarly quoted first-of-the-month natural gas index price. The fair value of such contracts was immaterial as of December 31, 2011 and 2010.

        The realized gains or losses on these derivatives, recognized in revenues in our statement of operations were as follows (in thousands):

 
   Year ended
December 31, 		 
 
   2012   2011   2010  

Realized gain / (loss) on derivatives

   $ (12 ) $ 179   $ 355  

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6. LONG-TERM DEBT

        Our long-term debt consisted of the following (in thousands):

 
   As of December 31,  
 
   2012   2011  

Credit Facility, due November 2017

   $ 191,000   $ —  

Credit Agreement, due June 2014

     —     208,280  
           

Total

     191,000     208,280  

Less:

              

Current maturities of long-term debt

     —     (17,490 )
           

Total long-term debt

   $ 191,000   $ 190,790  
           

        All of the Partnership's assets are pledged as collateral under the Credit Facility and the Credit Agreement. The terms of the Credit Facility and the Credit Agreement contain customary covenants, including those that restrict the Partnership's ability to make or limit certain payments, distributions, acquisitions, loans, or investments, incur certain indebtedness or create certain liens on its assets, consolidate or enter into mergers, dispose of certain of the Partnership's assets, engage in certain types of transactions with its affiliates, enter into certain sale/leaseback transactions and modify certain material agreements.

        Borrowings under the Credit Facility and the Credit Agreement bear interest at LIBOR plus an applicable margin or a base rate as defined in the respective credit agreements. Under the terms of the Credit Facility and the Credit Agreement, the applicable margin under LIBOR borrowings was 3.25% and 3.00% at December 31, 2012 and 2011, respectively. The weighted-average interest rate as of December 31, 2012 and 2011 was 3.95% and 3.58%, respectively.

        Our borrowings under the Credit Facility and the Credit Agreement were $191.0 million and $208.3 million as of December 31, 2012 and 2011, respectively, and our remaining available capacity under the Credit Facility was $132.7 million as of December 31, 2012, which was subsequently reduced as described below under "Amended Credit Facility." For the year ended December 31, 2012 and 2011, our average outstanding borrowings were $230.4 million and $147.4 million, respectively, and our maximum outstanding borrowings were $270.0 million and $212.7 million.

Credit Facility

        In connection with the closing of the IPO, the Partnership entered into a $350.0 million senior secured credit facility with Wells Fargo Bank, N.A., and a syndicate of lenders. The Partnership utilized the Credit Facility to fund fees and expenses incurred in connection with the IPO and for the repayment of a portion of the Southcross Energy LLC's debt under the Credit Agreement.

        The Partnership may utilize the Credit Facility for working capital requirements and capital expenditures, the purchase of assets, the payment of distributions, repurchase of units and general purposes of the Partnership. The Credit Facility matures on November 7, 2017, the fifth anniversary of the IPO closing date.

        Prior to amending our Credit Facility as discussed below, the Credit Facility included a sublimit of up to $75.0 million for letters of credit of which $26.3 million was outstanding as of December 31,

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2012. The Credit Facility also contained various covenants and restrictive provisions and required maintenance of certain financial and operational covenants including but not limited to the following:

        The Credit Facility also required the Partnership's Woodsboro gas processing plant and Bonnie View NGL fractionation facility to meet certain initial average daily processing volume requirements by December 31, 2012. Due to required operational ramp up time of the Bonnie View NGL fractionation facility, prior to December 31, 2012 the Partnership requested and received an extension of time to achieve the initial average daily processing volumes to January 31, 2013. The Partnership met the average daily processing volumes necessary to satisfy the Credit Facility's operational covenants in January 2013. The Partnership is not required to meet these average daily processing volumes on an ongoing basis to be in compliance with the Credit Facility.

        As of December 31, 2012, the Partnership was in compliance with all of its financial loan covenants. As discussed in Note 1, we believed it was unlikely that we would be in compliance with our financial covenants calculated for the quarter ending March 31, 2013, such that we negotiated with our lenders and secured more favorable financial covenants associated with our Credit Facility as further discussed below.

Amended Credit Facility

        On March 27, 2013, we entered into the First Amendment to the Credit Facility. As a result of the First Amendment, our letters of credit sublimit was reduced from $75.0 million to $31.5 million and our available credit was reduced from $350.0 million to $250.0 million, plus the sum of any amounts placed on deposit in the Collateral Account, plus letters of credit outstanding. As a condition to the First Amendment, our General Partner placed $10.0 million in the Collateral Account and that Collateral Account and the associated cash was pledged as collateral for the benefit of the lenders. Pursuant to the First Amendment, we are allowed to pay our quarterly cash distribution of available cash for the first quarter 2013 in an amount not to exceed $10 million on deposit in the Collateral Account.

        On April 12, 2013, we entered into the Second Amendment to the Credit Facility which waived our defaults relating to financial covenants for the period ending March 31, 2013 and provided more favorable financial covenants until we give notice under the Amended Credit Facility that we have achieved a Target Leverage Ratio (as defined in the Second Amendment) of 4.25 to 1.00 for one quarter or 4.50 to 1.00 for two consecutive quarters. Our available credit continues to be subject to the availability limits described in the First Amendment.

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6. LONG-TERM DEBT (Continued)

        The Second Amendment provides for, among other things, the following:

        As a condition to the Second Amendment, our General Partner deposited into the Collateral Account a total of $34.2 million, including the $10.0 million previously deposited under the First Amendment. Additionally Southcross Energy LLC and our General Partner agreed to deposit into the Collateral Account the proceeds they receive from cash distributions on units and that are attributable to the quarters ending March 31, 2013, June 30, 2013, September 30, 2013 and December 31, 2013.

        During the second quarter 2013, Southcross Energy LLC and/or our General Partner are required to make an equity investment in us in an aggregate amount equal to $40.0 million in exchange for new equity securities, which are required to be non-cash pay until the Target Leverage Test has been satisfied. On April 12, 2013 we entered into the Purchase Agreement to issue Series A Preferred Units in exchange for the investment of $40.0 million, utilizing the funds on deposit in the Collateral Account, to satisfy this requirement (See Note 14).

        After the application of the proceeds from the equity infusion on April 12, 2013, our available borrowing capacity was $27.2 million.

        If we fail to meet the Target Leverage Test on June 30, 2014, all or a portion of the cash distributions we made to Southcross Energy LLC and our General Partner for the quarters ending June 30, 2013, September 30, 2013 and December 31, 2013 deposited into the Collateral Account must be invested in us as additional non-cash pay equity securities.

        The Second Amendment requires us to have Consolidated EBITDA (as defined in the Credit Facility) of at least $9.0 million, for the quarter ending June 30, 2013, and we are not subject to a consolidated total leverage ratio for such quarter. The Second Amendment provides that until we satisfy the Target Leverage Ratio, we are allowed to calculate an adjusted consolidated total leverage ratio, which allows for the netting of total funded indebtedness with amounts on deposit in the

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6. LONG-TERM DEBT (Continued)

Collateral Account, and we may not permit our adjusted consolidated total leverage ratio to exceed the ratio set forth below for the corresponding period (as provided in the Amended Credit Facility):

 
   Maximum Adjusted
Consolidated
Total Leverage Ratio

September 30, 2013

   7.25 to 1.00

December 31, 2013

   6.75 to 1.00

March 31, 2014

   6.25 to 1.00

June 30, 2014

   5.25 to 1.00

September 30, 2014

   5.00 to 1.00

December 31, 2014

   4.75 to 1.00

March 31, 2015 and thereafter

   4.50 to 1.00

        Upon satisfying the Target Leverage Ratio, beginning with the quarter ending September 30, 2013, the Second Amendment provides that we will not permit our maximum consolidated total leverage ratio to exceed the ratio set forth below for the corresponding period (as provided in the Amended Credit Facility):

 
   Maximum Consolidated
Total Leverage Ratio

September 30, 2013

   4.75 to 1.00

December 31, 2013 and thereafter

   4.50 to 1.00

        The minimum consolidated interest coverage ratio was changed to 2.25 to 1.00 for the quarters ending September 30, 2013 and December 31, 2013 and 2.50 to 1.00 for the quarters ending March 31, 2014 and thereafter.

        If, for the calendar quarters ending on or before December 31, 2013, we fail to comply with the financial covenants of the Amended Credit Facility ("Financial Covenant Default") we have the right (which cannot be exercised more than two times) to cure such Financial Covenant Default by having Southcross Energy LLC and/or our General Partner deposit into the Collateral Account the amount required by the Second Amendment to cure such Financial Covenant Default.

Credit Agreement

        On August 6, 2009, in conjunction with the acquisition of businesses from Crosstex Energy LP and Southwest Energy, LP, Southcross Energy LLC borrowed $125.0 million and arranged for a $30.0 million revolver under the terms of a credit agreement executed among Southcross Energy LLC and a syndicate of lenders led by Wells Fargo Bank, N.A.

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6. LONG-TERM DEBT (Continued)

        On December 30, 2010, Southcross Energy LLC entered into the first amendment of that credit agreement, which extended the maturities of its debt from August 6, 2012 to June 30, 2014 and lowered the applicable interest rate margins. The terms of the amended credit agreement increased the term loan borrowings limit by $14.2 million to $115.0 million and, as a result, we increased borrowings by an incremental $14.2 million. Per the terms of the amended credit agreement, quarterly scheduled principal payments were reduced to $2.9 million commencing on March 31, 2011 with the remaining balance maturing on June 30, 2014. In addition, the amended credit agreement increased the limit on the use of the revolver on letters of credit to no more than $30.0 million and provided for the ability to expand the revolver to $55.0 million upon request by us.

        On June 10, 2011, Southcross Energy LLC entered into the Credit Agreement with a syndicate of lenders led by Wells Fargo Bank, N.A. with a maturity of June 10, 2016. Our term loan commitment increased from $115.0 million to $153.0 million in connection with the Credit Agreement, and we received net proceeds of $30.0 million. The Credit Agreement also gave us the right to draw down an additional term loan amount not to exceed $22.0 million by September 30, 2011. On August 30, 2011, Southcross Energy LLC borrowed an additional $21.9 million in the form of a LIBOR loan with an interest rate of 3.23% to fund the acquisition of EAI. The credit agreement also provided us with a current revolving loan capacity of $150.0 million which included a sub-limit of up to $50.0 million for letters of credit. This revolving loan capacity could be increased to $185.0 million by our request subject to certain conditions. Southcross Energy LLC used $120.7 million to pay off the existing loans, plus accrued interest, under the Credit Agreement. Per the terms of the Credit Agreement, we made a payment of $2.9 million on June 30, 2011 and thereafter quarterly scheduled principal payments of $4.4 million commencing on September 30, 2011, with the remaining balance maturing on June 10, 2016. For the year ended December 31, 2011, we made total principal repayments on the term loans of $16.4 million, including $1.9 million of principal repayments as a result of excess cash flow covenants.

        On February 7, 2012, Southcross Energy LLC entered into the first amendment of the Credit Agreement. The amendment was accounted for as a modification of an existing debt agreement and was entered into in order to modify the covenants to reflect the Southcross Energy LLC's need for expansion capital to support its growth plans. This amendment did not change the term loan or revolver loan capacity, but eased financial covenant measures and modified loan pricing for when the Southcross Energy LLC's leverage ratio was greater than 5.0 times to 1.0.

        On November 7, 2012, the Partnership, in connection with the IPO, assumed and repaid $270.0 million, representing all of the Southcross Energy LLC's outstanding debt under the Credit Agreement at that time.

        In 2012, we incurred a loss on the extinguishment of debt of $1.8 million in connection with the repayment $270.0 million of Southcross Energy LLC's assumed debt balance of following our IPO consisting of the partial write-down of deferred financing costs. In 2011, we incurred a loss on the extinguishment of debt of $3.2 million relating to the partial write-down of deferred financing costs on a previous credit agreement which was amended in June 2011.

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7. PROPERTY, PLANT AND EQUIPMENT

        Property, plant and equipment consist of the following (in thousands):

 
    
   As of December 31,  
 
   Estimated
Useful Life 		 
 
   2012   2011  

Pipelines

     30   $ 250,177   $ 230,866  

Gas processing, treating and other plants

     15     221,594     36,990  

Compressors

     7     19,241     16,078  

Rights of way and easements

     15     20,729     20,249  

Furniture, fixtures and equipment

     5     3,087     2,814  
                 

Total property, plant and equipment

           514,828     306,997  

Accumulated depreciation and amortization

           (46,466 )   (27,547 )
                 

Total

           468,362     279,450  

Construction in progress

           77,011     86,189  

Land and other

           5,230     4,222  
                 

Net property, plant and equipment

         $ 550,603   $ 369,861  
                 

        Depreciation is provided using the straight-line method based on the estimated useful life of each asset. Depreciation expense for the years ended December 31, 2012, 2011 and 2010 was $19.0 million, $12.3 million, and $11.0 million, respectively.

        Costs related to projects during construction, including interest on funds borrowed to finance the construction of facilities, are capitalized as construction in progress. For the years ended December 31, 2012, 2011 and 2010, the Partnership capitalized interest of $6.3 million, $1.8 million and $0, respectively. The Partnership had no capital leases as of December 31, 2012 and 2011.

8. INTANGIBLE ASSETS

        Intangible assets of $1.6 million and $1.7 million as of December 31, 2012 and 2011, respectively, represent the unamortized value assigned to the long-term supply and gathering contracts assumed by us in the EAI acquisition. The majority of assumed contracts are life of lease, and we determined that the useful economic lives of the underlying producing leases were at least as long as the expected life of the acquired pipelines. These intangible assets are amortized on a straight-line basis over the 30 year expected useful lives of the contracts. Amortization expense in the consolidated financial statements presented and over the next five years related to intangible assets for the periods presented is not material.

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9. OTHER ASSETS

        Other assets consisted of the following (in thousands):

 
   As of December 31,  
 
   2012   2011  

Deferred financing costs

   $ 4,385   $ 2,155  

Prepaid expenses

     551     2,040  

Other

     195     491  
           

Total other assets

   $ 5,131   $ 4,686  
           

        We incurred an additional $5.2 million in costs as a result of entering into amendments to the Credit Agreement and Credit Facility on February 7, 2012 and November 7, 2012, respectively. In addition, we incurred a loss on extinguishment related to a partial write-down of deferred financing costs of $1.8 million upon the settlement of the Credit Agreement in November 2012. These deferred financing costs are being amortized over the remaining life of the Credit Facility through the maturity date of November 2017. Amortization of deferred financing costs recorded in interest expense was $1.2 million, $0.9 million, and $2.2 million for the years ended December 31, 2012, 2011, and 2010, respectively.

10. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

        Accounts payable and accrued liabilities consisted of the following (in thousands):

 
   As of December 31,  
 
   2012   2011  

Trade accounts payable

   $ 87,981   $ 47,311  

Accrued liabilities

     8,820     3,128  
           

Total accounts payable

   $ 96,801   $ 50,439  
           

        Trade accounts payable as of December 31, 2012 and 2011 included $40.7 million and $10.9 million, respectively, related to capital expenditures.

11. COMMITMENTS AND CONTINGENT LIABILITIES

Legal Matters

        From time to time, we are party to certain legal or administrative proceedings that arise in the ordinary course and are incidental to our business. There are currently no such pending proceedings to which we are a party that our management believes will have a material adverse effect on our results of operations, cash flows or financial condition. However, future events or circumstances, currently unknown to management, will determine whether the resolution of any litigation or claims will ultimately have a material effect on our results of operations, cash flows or financial condition in any future reporting periods. We have not been involved in any significant claims or litigation for the years ended December 31, 2012, 2011 and 2010, respectively, (See Note 19) and had no litigation accrual as of December 31, 2012 or December 31, 2011.

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11. COMMITMENTS AND CONTINGENT LIABILITIES (Continued)

Regulatory Compliance

        In the ordinary course of our business, we are subject to various laws and regulations. In the opinion of our management, compliance with current laws and regulations will not have a material effect on our results of operations, cash flows or financial condition.

Commitments and Purchase Obligations

Operating Leases

        We maintain operating leases in the ordinary course of our business activities. These leases include those for vehicles, office buildings and other operating facilities and equipment. The terms of the agreements vary from 2013 until 2016. Future minimum annual rental commitments under our operating leases at December 31, 2012 were as follows (in thousands):

Years Ending
December 31,
  Operating Leases  

2013

   $ 846  

2014

     818  

2015

     552  

2016

     264  

2017

     —  
       

Total

   $ 2,480  
       

        Expenses associated with operating leases were $2.2 million, $1.5 million, and $1.2 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Purchase Commitments

        At December 31, 2012, we had commitments of approximately $8.2 million to purchase equipment related to our capital projects. We have other planned capital projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.

12. INCOME TAXES

        We are responsible for our portion of the Texas margin tax that is included in Southcross Energy LLC's consolidated Texas franchise tax return. Our current tax liability is assessed based on gross revenue, less certain costs, apportioned to Texas. The margin tax qualifies as an income tax under GAAP, which requires us to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax. For the years ended December 31, 2012, 2011 and 2010, there were no temporary differences recognized in our consolidated statements of operations.

        We believe that there are no uncertain tax positions that would impact our operations for the years ended December 31, 2012, 2011 and 2010 and that no provision for income tax is required for these consolidated financial statements. However, our conclusions regarding the evaluation are subject to review and may change based on factors including, but not limited to, ongoing analyses of tax laws, regulations and interpretations thereof.

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13. TRANSACTIONS WITH RELATED PARTIES

Charlesbank

        Historically, Charlesbank provided certain management services to Southcross Energy LLC pursuant to a management services agreement ("Charlesbank Agreement") which specified an annual management fee of $0.6 million. Southcross Energy LLC received services under the Charlesbank Agreement up to the IPO. Subsequent to the IPO, the Partnership did not receive any further services under this agreement, as the Charlesbank Agreement terminated with the IPO.

        For the years ended December 31, 2012, 2011 and 2010, Southcross Energy LLC incurred management fees of $0.5 million, $0.6 million and $0.6 million, respectively, for services received and incurred associated expenses of $68,000, $109,000 and $29,000, respectively under the Charlesbank Agreement. Services fees and expenses under the Charlesbank Agreement are recognized in general and administrative expenses in our consolidated statements of operations. After February 7, 2012 the payment of fees and expenses under the Charlesbank Agreement was not allowed under the Credit Agreement. Therefore, no payments for services provided, relating to 2012, were made under the Charlesbank Agreement.

Wells Fargo Bank, N.A.

        The Partnership entered into the credit agreements with syndicates of financial institutions and other lenders. These syndicates included affiliates of Wells Fargo Bank, N.A., an affiliate of which is a member of the investor group (See Note 15). Affiliates of Wells Fargo Bank, N.A. have from time to time engaged in commercial banking and financial advisory transactions with the Company in the normal course of business. Total fees paid, excluding interest, to affiliates of Wells Fargo, N.A., and its affiliates were $5.9 million, $1.0 million and $0.4 million for 2012, 2011 and 2010, respectively.

14. PARTNERS' CAPITAL AND MEMBERS' EQUITY

Partners' Capital

        On November 7, 2012, Southcross completed its IPO and after the completion of the IPO and full exercise of the underwriters' over-allotment option, Southcross Energy LLC's direct and indirect equity ownership in the Partnership was 58.5%. Through a series of transactions described below, Southcross Energy LLC contributed all of its operating subsidiaries (its net assets on a historical cost basis), excluding certain liabilities and all preferred units, and became the holding company of the Partnership. Southcross Energy LLC holds all of the equity interests in the General Partner, as well as all subordinated units and a portion of the common units of the Partnership. Subsequent to the IPO, the Partnership owns Southcross Energy LLCs' operating subsidiaries.

        The following activities occurred in connection with the closing of the IPO:

Activity of Southcross Energy LLC

        Southcross Energy LLC conveyed the following:

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14. PARTNERS' CAPITAL AND MEMBERS' EQUITY (Continued)

Activity of the General Partner

        The General Partner conveyed its interest in Southcross Operating to the Partnership in exchange for:

Activity of the Partnership

        The Partnership completed its IPO, receiving proceeds of approximately $168.0 million, net of underwriters' discounts and structuring fees, and:

        In connection with the full exercise of the underwriter's over-allotment option, which closed on November 26, 2012, the following additional activity of the Partnership occurred:

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14. PARTNERS' CAPITAL AND MEMBERS' EQUITY (Continued)

Common units

        Our common units represent limited partner interests in us. The holders of our common units are entitled to participate in partnership distributions and are entitled to exercise the rights and privileges available to limited partners under our partnership agreement. We have authorized 13,963,713 common units as of December 31, 2012.

Subordinated units

        Subordinated units represent limited partner interest in us and convert to common units at the end of the subordination period (as defined in our partnership agreement). 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 do not accrue arrearages.

General Partner interests

        Our general partner interest consisted of 498,518 general partner units as of December 31, 2012 and as defined by the Partnership's partnership agreement are not considered to be units (Common or Subordinated) under the partnership agreement and are representative of the general partner's 2% interest in us. Subsequent to December 31, 2012 and in conjunction with the Private Placement discussed below, our General Partner made a capital contribution in the amount of $0.7 million on April 12, 2013 in order to maintain its 2% ownership interest in us.

Private Placement of Series A Convertible Preferred Units

        On April 12, 2013 (the "Issue Date"), we entered into a Series A Preferred Unit Purchase Agreement (the "Purchase Agreement") with Southcross Energy LLC, pursuant to which we issued and sold 1,466,325 Series A Preferred Units to Southcross Energy LLC for a cash purchase price of $22.86 per Series A Preferred Unit in a privately negotiated transaction (the "Private Placement").

        The Series A Preferred Units are a new class of voting equity security that ranks senior to all of our other classes or series of equity securities with respect to distribution rights and rights upon liquidation.

        The Series A Preferred Units have voting rights identical to the voting rights of the common units and will vote with the common units as a single class, such that each Series A Preferred Unit (including each Series A Preferred Unit issued as an in-kind distribution, discussed below) is entitled to one vote for each common unit into which such Series A Preferred Unit is convertible on each matter with respect to which each common unit is entitled to vote.

        The Private Placement resulted in proceeds to us of $33.5 million. We also received a $0.7 million capital contribution from our General Partner to maintain its 2.0% general partner interest in us. When we sell to Southcross Energy LLC the additional 248,675 Series A Preferred Units for $5.7 million, our General Partner will make an additional capital contribution to us of $0.1 million.

        The total capital infusion to the Partnership of $40.0 million, from all sales of Series A Preferred Units and General Partner capital contributions, were and will be used to reduce borrowings under our amended Credit Facility (See Note 6).

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14. PARTNERS' CAPITAL AND MEMBERS' EQUITY (Continued)

Series A Preferred Unit Distribution Rights

        Holders of Series A Preferred Units are entitled to quarterly distributions of in-kind Series A Preferred Units for the first four full quarters following the Issue Date and continuing thereafter until the board of directors of our General Partner determines to begin paying quarterly distributions in cash, and thereafter in cash. The board of directors of our General Partner may not elect to begin paying quarterly distributions on the Series A Preferred Units in cash until we have exercised the Target Leverage Option (pursuant to the Second Amendment) under our Amended Credit Facility.

        In-kind distributions will be made in the form of Series A Preferred Units at a rate of $0.40 per outstanding Series A Preferred Unit per quarter (or 7% per year of the per unit purchase price) or, beginning after four full quarters, such higher per unit rate as is paid in respect of our common units. Cash distributions will equal the greater of $0.40 per unit per quarter or the quarterly distribution paid with respect to each common unit.

Series A Preferred Units Conversion Rights

        Beginning on the later of January 1, 2015 and the date we exercise the Target Leverage Option (pursuant to the Second Amendment), Series A Preferred Units (including Series A Preferred Units issued as in-kind distributions) will be convertible into common units on a one-for-one basis, except that conversion will be prohibited to the extent that it would cause (on a pro forma basis) our estimated quarterly distributions over any of the succeeding four quarters to exceed our total distributable cash flow in that quarter. In addition, the Series A Preferred Units will be convertible into common units having a collective value of 110% of the Series A Preferred Units if a third party acquires majority ownership control of our general partner or we sell substantially all of our assets, in either case prior to January 1, 2015.

        Beginning on January 1, 2015, we will have the right at any time to convert all or some of the Series A Preferred Units (including Series A Preferred Units issued as in-kind distributions) then outstanding into common units if (i) the daily volume-weighted average trading price of the common units on the national securities exchange on which the common units are listed or admitted to trading is greater than 130% of the unit purchase price for the trailing 30-trading-day period prior to our notice of conversion, (ii) the average daily trading volume of common units on the securities exchange exceeds 40,000 common units for those 30 trading days and (iii) the conversion would not cause (on a pro forma basis) our estimated quarterly distributions over any of the succeeding four quarters to exceed our total distributable cash flow in that quarter.

Members' Equity of Southcross Energy LLC

        On August 6, 2009, five members of the Southcross Energy LLC's management team purchased, directly or indirectly through Estrella Energy, LP, Class A common units and Class B units along with Charlesbank, for the same value as Charlesbank, ($1.00 per unit). Estrella Energy, LP was partially owned by a non-management third-party, and thus a portion of the time- and performance-based units ("Third-Party Units") owned by Estrella Energy, LP were owned indirectly by the non-management third-party.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14. PARTNERS' CAPITAL AND MEMBERS' EQUITY (Continued)

        As of December 31, 2011, Southcross Energy LLC's common equity was comprised of 1,415,729 Class A authorized and outstanding common units, of which 217,483 were unvested, and 57,279 authorized and outstanding Class B units, of which 34,367 were unvested. The Class B units have the same distribution and liquidation rights as the Class A common units; however, they do not have voting rights. All Class A common units and Class B units were sold for, and have a par value of, $1.00 per unit.

        Certain of the Class A common units and all of the Class B units contain time- and performance-vesting conditions. Time-vesting units vest ratably over five years subject to certain accelerated vesting based primarily on change of control or certain termination causes. Performance-vesting units will vest, if at all, upon Charlesbank attaining certain investment multiples and internal rates of return in connection with a liquidity event. Both the time- and performance vesting units require continued employment through any vesting date. The change in structure and ownership as a result of the IPO did not create a change of control event under the terms of the time- and performance-vesting units.

        On March 20, 2012, Estrella Energy, LP was dissolved and Southcross Energy LLC purchased and retired the Third-Party Units for $15.3 million. Management did not receive any consideration in connection with such repurchase.

15. SOUTHCROSS ENERGY LLC PREFERRED UNITS

        In connection with the IPO and through a series of transactions described in Note 14, Southcross Energy LLC contributed all of its operating subsidiaries (its net assets on a historical cost basis), excluding certain liabilities, common units and all preferred units, and became the holding company of the Partnership. This note discloses Southcross Energy LLC's preferred units as of November 7, 2012 (the IPO date) and December 31, 2011, as well as the activity associated with the preferred units for the period from January 1, 2012 through the IPO and for the years ended 2011 and 2010.

        None of the preferred units (Preferred, Redeemable Preferred and Series B Redeemable Preferred) were conveyed in the IPO, and remain the obligation of Southcross Energy LLC and not the Partnership.

Preferred Units

        As of November 7, 2012 and December 31, 2011, Southcross Energy LLC's cumulative preferred units were comprised of 11,850,374 units with a par value of $10 per unit, which accrued value (in the form of additional preferential rights to receive distributions) at a rate of 10% per annum, compounded quarterly.

        Except in the case of cash distributions made for the purpose of paying federal income taxes, which are made to both preferred and common equity owners in direct proportion to the owners' respective share of taxable income, owners of the preferred equity receive cash distributions before owners of common equity. The cumulative preferred units and their cumulative return are subordinated to all redeemable preferred units and their cumulative return as discussed below. With the exception of cash distributions for federal income tax purposes, the Credit Agreement included certain covenants that restricted Southcross Energy LLC's ability to pay cash dividends to its owners. Southcross Energy LLC adjusts the carrying value of the Preferred Units to reflect the cumulative right to receive distributions on a quarterly basis. As of November 7, 2012, and December 31, 2011, the preferred units'

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SOUTHCROSS ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

15. SOUTHCROSS ENERGY LLC PREFERRED UNITS (Continued)

cumulative right to receive future cash distributions was $43.3 million and $31.8 million, respectively, as a result of the cumulative preferred return on such units.

Redeemable Preferred Units

        As mentioned above, none of the redeemable preferred units were conveyed in the IPO, and they remain the obligation of Southcross Energy LLC. On June 10, 2011, in connection with Southcross Energy LLC entering into the Credit Agreement, Charlesbank and certain of Southcross Energy LLC's existing investors contributed a total of $15.0 million in exchange for 1.5 million Redeemable Preferred Units. The Redeemable Preferred Units have a par value of $10 per unit and accrue value (in the form of an additional preferential right to receive distributions) at a rate of 18% per annum, compounded quarterly. These Redeemable Preferred Units could be redeemed in whole or in part at any time, or would be redeemed by Southcross Energy LLC promptly after the satisfaction of all obligations under the Credit Agreement, to the extent of available funds. Southcross Energy LLC adjusted the carrying value of the Redeemable Preferred Units to reflect the cumulative right to receive distributions on a quarterly basis. As of November 7, 2012 and December 31, 2011, the right of the Redeemable Preferred Units to receive future cash distributions included an additional $3.9 million and $1.6 million, respectively, as a result of the cumulative preferred return on such units.

Series B Redeemable Preferred Units

        As mentioned above, none of the redeemable preferred units were conveyed in the IPO, and they remain the obligation of Southcross Energy LLC. On March 20, 2012, Charlesbank and certain of Southcross Energy LLC's existing investors contributed $25.3 million and an affiliate of Wells Fargo Securities, LLC contributed $10.0 million to Southcross Energy LLC in exchange for 2.53 million units and 1.0 million units, respectively, of a new, Series B class, of Redeemable Preferred Units ("Series B Units"). On June 26, 2012, Charlesbank and certain of Southcross Energy LLC's existing investors contributed $7.5 million to Southcross Energy LLC in exchange for 0.75 million Series B Units.

        On November 7, 2012 and subsequent to the IPO, the Series B Units were comprised of 3.35 million units. On November 26, 2012 and subsequent to the Over-Allotment Option, Southcross Energy LLC redeemed 2.49 million units. The Series B Units have a par value of $10 per unit, which accrue value (in the form of an additional preferential right to receive distributions) at a rate of 18% per annum, compounded quarterly. The Series B Units could be redeemed by Southcross Energy LLC in whole or in part at any time, or would be redeemed by Southcross Energy LLC promptly after the satisfaction of all its obligations under the Credit Agreement, to the extent of available funds. Southcross Energy LLC adjusts the carrying value of the Series B Units to reflect the cumulative right to receive distributions on a quarterly basis. As of November 7, 2012 and November 26, 2012, the Series B Units' right to receive future cash distributions included $3.8 million and $4.4 million, respectively as a result of the cumulative preferred return.

Series C Redeemable Preferred Units

        As mentioned above, none of the redeemable preferred units were conveyed in the IPO, and they remain the obligation of Southcross Energy LLC. On June 26, 2012, Charlesbank and certain of Southcross Energy LLC's existing investors and other institutional investors contributed $30.0 million to Southcross Energy LLC in exchange for 3.0 million units of a new, Series C class, of Redeemable

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SOUTHCROSS ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

15. SOUTHCROSS ENERGY LLC PREFERRED UNITS (Continued)

Preferred Units ("Series C Units"). As of November 7, 2012, the Series C Units were comprised of 3.0 million units with a par value of $10 per unit, which accrue value (in the form of an additional preferential right to receive distributions) at a rate of 18% per annum, compounded quarterly. The Series C Units and their cumulative preferred return of $1.4 million as of November 7, 2012 were fully redeemed in connection with the IPO (See Note 14).

16. UNIT BASED COMPENSATION

Long-Term Incentive Plan

        On November 7, 2012, and in conjunction with the IPO, the Partnership established its 2012 Long-Term Incentive Plan ("Incentive Plan"), which provides incentive awards to eligible officers, employees and directors of our General Partner. Awards granted to employees under the Incentive Plan vest over a three year period in equal annual installments in either a common unit of the Partnership or an amount of cash equal to the fair market value of a common unit at the time of vesting, as determined by management at its discretion. These awards also include distribution equivalent rights which grants the holder the right to receive an amount equal to all or a portion of the cash distributions made on units during the period the unit remains outstanding.

        The following table summarizes information regarding the Incentive Plan unit activity:

 
   Units   Weighted-average
grant date fair value 		 

Unvested—December 31, 2011

     —   $ —  

Granted units

     146,000     23.01  

Forefeited units

     (1,500 )   23.01  

Vested units

     —     —  
           

Unvested—December 31, 2012

     144,500   $ 23.01  
           

        We granted awards under the Incentive Plan, which we have classified as equity awards, with a grant date fair value of approximately $3.4 million for the year ended December 31, 2012. As of December 31, 2012, we had total unamortized compensation expense of approximately $3.2 million related to these units, which we expect to be amortized over the three-year vesting period. We recognized compensation expense of approximately $0.2 million for the year ended December 31, 2012, included in general and administrative expense on our consolidated statements of operations. As of December 31, 2012, we had 1,605,500 units available for issuance under the Incentive Plan.

Southcross Energy LLC Phantom Units

        Southcross Energy LLC provided certain key non-officer employees with equity incentive units ("Phantom Units") in Southcross Energy LLC. The Phantom Units vest upon the occurrence of a change in control where more than 50% of the voting power of Southcross Energy LLC changes hands, or upon the occurrence of a liquidity event where, through the sale of some portion of its ownership, the majority owner of Southcross Energy LLC achieves or exceeds a targeted rate of return on its original investment. The changes in structure and ownership as a result of the IPO did not create a change of control event under the vesting terms of the Phantom Units. The number of Phantom Units earned and eligible for vesting increases over a period of years or through the achievement of certain

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SOUTHCROSS ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. UNIT BASED COMPENSATION (Continued)

rates of return by the majority owner of the Southcross Energy LLC or a combination thereof. As of December 31, 2012 and 2011, no fair value was attributable to the Phantom Units. No compensation expense associated with these units was recorded during the year ended December 31, 2012 and 2011. As of December 31, 2012 and 2011 the number of authorized and issued Phantom Units was 10,832.

Southcross Energy LLC Executive Equity Equivalent Units

        On April 1, 2012, Southcross Energy LLC granted 15,000 equity equivalent units ("EEUs") to a member of management. Each individual EEU is equivalent in economic value to one Class A Common Unit of Southcross Energy LLC on a fully diluted basis. The EEUs have time and performance vesting over a three year term. The Partnership recognized $0.4 million in compensation expense in 2012.

17. REVENUES

        The Partnership had revenues consisting of the following categories (in thousands):

 
   Year ended December 31,  
 
   2012   2011   2010  

Sales of natural gas

   $ 325,421   $ 385,513   $ 379,476  

Sales of NGLs and condensate

     124,139     106,487     93,592  

Transportation, gathering and processing fees

     46,113     30,102     25,080  

Other

     456     1,047     599  
               

Total revenues

   $ 496,129   $ 523,149   $ 498,747  
               

18. CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE

        The Partnership's primary markets are in South Texas, Alabama and Mississippi. The Partnership has a concentration of revenues and trade accounts receivables due from customers engaged in the production, trading, distribution and marketing of natural gas and NGL products. These concentrations of customers may affect overall credit risk in that these customers may be similarly affected by changes in economic, regulatory or other factors. The Partnership analyzes the customers' historical financial and operational information prior to extending credit.

        Formosa Hydrocarbons Company Inc. ("Formosa") and Sherwin Alumina Company ("Sherwin") were significant customers for the Partnership. Formosa and Sherwin contributed $120.4 million or 24.3% and $54.5 million or 11.0%, respectively, of revenues in 2012, $108.8 million or 20.8% and $81.2 million or 15.5%, respectively, of revenues in 2011, and $106.6 million or 21.4% and $65.4 million or 13.1%, respectively, of revenues in 2010. In January 2013, we signed an amendment with Formosa defining volumes subject to the gas processing contract between the parties which expires May 31, 2013 (See Note 19).

        The Partnership's top ten customers represent 65.5%, 73.1% and 74.2% of consolidated revenue for the years ended December 31, 2012, 2011, and 2010, respectively.

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SOUTHCROSS ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18. CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE (Continued)

        During the years ended December 31, 2012, 2011, and 2010 we experienced no significant non-payment for services. At December 31, 2012 and 2011, we have recorded no allowance for uncollectable accounts receivable.

19. SUBSEQUENT EVENTS

Formosa Amendment

        On January 24, 2013 we signed an amendment with Formosa whereby the volumes of our natural gas that can be processed through Formosa gradually decreases between January 2013 and the agreement termination date of May 31, 2013, after which all of our rich gas will be routed to our Woodsboro processing plant, our Gregory processing plant, and, if necessary, to other third party processing plants.

Gregory Processing and NGL Fractionation Facility

        Our Gregory facility includes 135 MMcf/d of gas processing capacity and an associated 4,800 Bbls/d NGL fractionation facility. We shut down this plant in January 2013 to perform extensive turnaround maintenance activities and connect additional equipment to enhance NGL recoveries. As the turnaround maintenance was nearing completion, on January 26, 2013, we experienced a fire at this facility. Damage was limited to a small portion of the facility and we completed repairs and resumed operations during April 2013.

Partnership Distribution

        On February 1, 2013, we announced a pro-rated cash distribution of $0.24 per common and subordinated unit for the fourth quarter of 2012, which was paid on February 14, 2013 to unit holders of record on February 11, 2013. This distribution is the first declared by the Partnership and corresponds to the minimum quarterly distribution of $0.40 per unit, or $1.60 on an annualized basis, pro-rated for the portion of the quarter following the closing of the IPO on November 7, 2012.

Bonnie View NGL Fractionation Facility

        In February 2013, we completed the expansion of our NGL capacity at our Bonnie View fractionation facility from 11,500 Bbls/d to 22,500 Bbls/d. The plant fractionates y-grade NGLs from our Woodsboro processing plant and produces NGL component products.

Bee Line Gas Pipeline Commences Operations

        In February 2013, we completed construction of 57 miles of 20-inch pipeline to move rich gas to our Woodsboro processing plant. The Bee Line pipeline has capacity to bring of 320 MMcf/d.

Formosa Litigation

        On March 5, 2013, a subsidiary of the Partnership filed suit against Formosa. The lawsuit seeks recoveries of losses which we believe our subsidiary experienced as a result of the failure of Formosa to perform certain of its obligations under the gas processing contract between the parties. We cannot predict the outcome of such litigation.

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SOUTHCROSS ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19. SUBSEQUENT EVENTS (Continued)

Credit Facility

        As further discussed in Note 6, on March 27, 2013, we entered into the First Amendment to the Credit Facility. On April 12, 2013, we entered into the Second Amendment to the Credit Facility which waived our defaults relating to financial covenants for the period ending March 31, 2013 and provides us with more favorable financial covenants than were provided previously and we believe these more favorable terms will allow us to operate our business and continue to meet our commitments.

Series A Convertible Preferred Units

        As further discussed in Note 14, on April 12, 2013, to satisfy our requirements under our Amended Credit Facility as discussed above, we entered into a Series A Convertible Preferred Unit Purchase Agreement with Southcross Energy LLC, pursuant to which we issued and sold 1,466,325 Series A Convertible Preferred Units (the "Series A Preferred Units") and agreed to sell, by June 30, 2013, an additional 248,675 Series A Preferred Units to Southcross Energy LLC for a cash purchase price of $22.86 per Series A Preferred Unit in a privately negotiated transaction (the "Private Placement").

        The Private Placement resulted in proceeds to us of $33.5 million. We also received a $0.7 million capital contribution from our General Partner to maintain its 2.0% general partner interest in us. When we sell to Southcross Energy LLC the additional 248,675 Series A Preferred Units for $5.7 million, our General Partner will make an additional capital contribution to us of $0.1 million.

        The total capital infusion to the partnership of $40.0 million from all sales of Series A Preferred Units and General Partner capital contributions were and will be used to reduce borrowings under our amended Credit Facility providing us with additional borrowing capacity (See Note 6).

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SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

        The following presents a summary of selected quarterly financial information (in thousands, except per unit data)

 
    
    
    
   Periods ended    
  
 
   Quarters ended    
  
 
   October 1, 2012-
November 6, 2012(1) 		  November 7, 2012-
December 31, 2012(1)(2) 		   
  
2012
  March 31   June 30   September 30   Total  

Revenues

   $ 120,618   $ 105,701   $ 118,150   $ 55,613   $ 96,047   $ 496,129  

Gross operating margin

     21,416     18,698     15,078     6,741     9,707     71,640  

Operating income

     14,219     10,317     6,187     2,290     3,095     36,108  

Net income (loss)

   $ 6,236   $ 1,939   $ (4,041 ) $ (4,394 ) $ (4,228 ) $ (4,488 )

General partner's interest in net loss

                           $ (85 ) $ (85 )

Limited partners' interest in net loss

                           $ (4,143 ) $ (4,143 )

General partners' net loss per unit—basic and diluted

                           $ (0.17 ) $ (0.17 )

Limited partners' net loss per unit—basic and diluted

                           $ (0.17 ) $ (0.17 )

 

 
   Quarters ended    
    
  
2011
  March 31   June 30   September 30   December 31       
   Total  

Revenues

   $ 120,999   $ 126,490   $ 135,961   $ 139,699         $ 523,149  

Gross operating margin

     15,247     15,116     13,473     18,733           62,569  

Operating income

     10,413     9,658     7,001     10,790           37,862  

Net income (loss)

   $ 4,205   $ (171 ) $ 199   $ 3,306         $ 7,539  
(1)
See Note 1 for a description of decreases in results of operations during this period.

(2)
Represents results of Southcross Energy Partners, L.P. subsequent to our intial public offering on November 7, 2012.

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Item 9.    Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

        None

Item 9A.    Controls and Procedures

        We maintain controls and procedures designed to ensure that information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our General Partner's Chief Executive Officer (our principal executive officer) and our General Partner's Chief Financial Officer (our principal financial officer), as appropriate, to allow for timely decisions regarding required disclosure. An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Securities Exchange Act of 1934 was performed as of December 31, 2012. This evaluation was performed by our management, with the participation of our General Partner's Chief Executive Officer and Chief Financial Officer. Based on this evaluation, our General Partner's Chief Executive Officer and Chief Financial Officer concluded that these disclosure controls and procedures are effective to ensure that we are able to collect, process and disclose the information we are required to disclose in the reports we file with the SEC within the required time periods.

        This annual report does not include a report of management's assessment regarding internal control over financial reporting or an attestation report of the Partnership's registered public accounting firm due to a transition period established by rules of the Securities and Exchange Commission for newly public companies.

Changes in Internal Control

        No changes in our internal control over financial reporting occurred during the year ended December 31, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.    Other Information

        Item 1.01 Entry into a Material Definitive Agreement.

        On April 12, 2013 (the "Issue Date"), we entered into a Series A Convertible Preferred Unit Purchase Agreement (the "Purchase Agreement") with Southcross Energy LLC, an entity owned by investment funds and entities associated with Charlesbank Capital Partners, LLC, and certain members of our management team and that owns and controls Southcross Energy GP, LLC, our general partner ("General Partner") and an approximate 56.5% interest in us (the "Purchaser"), pursuant to which we issued and sold 1,466,325 Series A Convertible Preferred Units (the "Series A Preferred Units") to the Purchaser for a cash purchase price of $22.86 per Series A Preferred Unit (the "Unit Purchase Price") in a privately negotiated transaction (the "Private Placement").

        The Private Placement resulted in proceeds to us of $33.5 million. We also received a $0.7 million capital contribution from our General Partner to maintain its 2.0% general partner interest in us. Under the Purchase Agreement, we will issue an additional 248,675 Series A Preferred Units at the same Unit Purchase Price to the Purchaser by June 30, 2013 for $5.7 million and our General Partner will make an additional capital contribution to us of $0.1 million. The total capital infusion to the Partnership of $40.0 million from all sales of Series A Preferred Units and General Partner capital contributions were and will be used to reduce borrowings under our Amended Credit Facility providing us with additional borrowing capacity.

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        The Purchase Agreement contains customary terms for private placements by public companies, including customary representations, warranties, covenants and indemnities.

        The foregoing description of the Purchase Agreement does not purport to be complete and is qualified in its entirety by reference to the Purchase Agreement, a copy of which is filed as Exhibit 10.10 to this Annual Report on Form 10-K and is incorporated herein by reference.

        The Series A Preferred Units are a new class of voting equity security that ranks senior to all of our other classes or series of equity securities with respect to distribution rights and rights upon liquidation.

        Holders of the Series A Preferred Units are entitled to quarterly distributions of in-kind Series A Preferred Units for the first four full quarters following the Issue Date and continuing thereafter until the board of directors of our General Partner determines to begin paying quarterly distributions in cash, and thereafter in cash. The board of directors of our General Partner may not elect to begin paying quarterly distributions on the Series A Preferred Units in cash until we have exercised the Target Leverage Option (as defined below) under our amended credit facility.

        In-kind distributions will be made in the form of Series A Preferred Units at a rate of $0.40 per outstanding Series A Preferred Unit per quarter (or 7% per year of the per-unit purchase price) or, beginning after four full quarters, such higher per unit rate as is paid in respect of our common units. Cash distributions will equal the greater of $0.40 per unit per quarter or the quarterly distribution paid with respect to each common unit.

        Beginning on the later of January 1, 2015 and the date we exercise the Target Leverage Option, Series A Preferred Units (including Series A Preferred Units issued as in-kind distributions) will be convertible into common units on a one-for-one basis, except that conversion will be prohibited to the extent that it would cause (on a pro forma basis) our estimated quarterly distributions over any of the succeeding four quarters to exceed its total distributable cash flow in that quarter. In addition, the Series A Preferred Units will be convertible into common units having a collective value of 110% of the Series A Preferred Units if a third party acquires majority ownership control of our General Partner or we sell substantially all of our assets, in either case prior to January 1, 2015.

        Beginning on January 1, 2015, we will have the right at any time to convert all or some of the Series A Preferred Units (including Series A Preferred Units issued as in-kind distributions) then outstanding into common units if (i) the daily volume-weighted average trading price of the common units on the national securities exchange on which the common units are listed or admitted to trading is greater than 130% of the Unit Purchase Price for the trailing 30-trading-day period prior to our notice of conversion, (ii) the average daily trading volume of common units on the securities exchange exceeds 40,000 common units for those 30 trading days and (iii) the conversion would not cause (on a pro forma basis) our estimated quarterly distributions over any of the succeeding four quarters to exceed our total distributable cash flow in that quarter.

        The Series A Preferred Units have voting rights identical to the voting rights of the common units and will vote with the common units as a single class, such that each Series A Preferred Unit (including each Series A Preferred Unit issued as an in-kind distribution) is entitled to one vote for each common

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unit into which such Series A Preferred Unit is convertible on each matter with respect to which each common unit is entitled to vote.

        The foregoing description of the Series A Preferred Units does not purport to be complete and is qualified in its entirety by reference to our Second Amended and Restated Agreement of Limited Partnership, a copy of which is filed as Exhibit 3.2 to this Annual Report on Form 10-K and is incorporated herein by reference.

        On the Issue Date, we entered into a Registration Rights Agreement with the Purchaser. Pursuant to the Registration Rights Agreement, we have agreed, after we become eligible to use the Form S-3 registration statement to register resales of our common units, to file up to two shelf registration statements for the resale of the common units into which the Series A Preferred Units may convert following receipt of written notice from the Purchaser. In addition, we have agreed to use commercially reasonable efforts to cause each shelf registration statement to be declared effective by the Securities and Exchange Commission no later than 180 days after its filing. The Registration Rights Agreement also provides the Purchaser with rights that allow the Purchaser to include its common units in certain registered offerings that we conduct for our own account. The Registration Rights Agreement contains representations, warranties, covenants and indemnities that are customary for private placements by public companies.

        The foregoing description of the Registration Rights Agreement does not purport to be complete and is qualified in its entirety by reference to the Registration Rights Agreement, a copy of which is filed as Exhibit 4.1 to this Annual Report on Form 10-K and is incorporated herein by reference.

        The Purchaser is owned by investment funds and entities affiliated with Charlesbank Capital Partners, LLC, and certain members of our management team, and the Purchaser owns and controls our General Partner and an approximate 59.2% interest in us (giving effect to the issuance to the Purchaser of Series A Preferred Units as contemplated under the Purchase Agreement). Certain individuals, including officers and directors of our General Partner, are also members of the Purchaser.

        The transactions contemplated by the Purchase Agreement and the Registration Rights Agreement were approved by the conflicts committee of the board of directors of our General Partner. The conflicts committee, which is comprised entirely of independent directors, retained independent legal and financial advisors to assist it in evaluating the transaction.

        On April 12, 2013, we entered into the Limited Waiver and Second Amendment to the Senior Secured Credit Facility (the "Second Amendment") in order to provide more favorable financial covenants until we achieve a target leverage ratio (as defined in the Second Amendment).

        As a condition to the Second Amendment, our General Partner agreed to place an additional $24.2 million in the Collateral Account and our General Partner and Southcross Energy LLC agreed to deposit the proceeds they receive from any distributions attributable to the quarters ending March 31, 2013, June 30, 2013, September 30, 2013 and December 31, 2013 into the Collateral Account.

        Pursuant to the Second Amendment:

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        The foregoing description of the Second Amendment does not purport to be complete and is qualified in its entirety by reference to the Second Amendment, a copy of which is filed as Exhibit 10.5 to this Annual Report on Form 10-K and is incorporated herein by reference.

        Item 2.03 Creation of a Direct Financial Obligation or an Obligation under an Off-Balance Sheet Arrangement of a Registrant.

        The disclosures under Item 1.01 of this Part 9B relating to our Second Amended and Restated Agreement of Limited Partnership are incorporated into this Item 2.03 by reference.

        Item 3.02 Unregistered Sales of Equity Securities.

        The disclosures under Item 1.01 above relating to our Private Placement are incorporated into this Item 3.02 by reference. The Series A Preferred Units were issued and sold pursuant to the Purchase Agreement in a transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended, and the rules and regulations promulgated thereunder.

        Item 3.03 Material Modification to Rights of Security Holders.

        The disclosures under Item 1.01 above relating to our Private Placement, the execution of the Registration Rights Agreement and the effect of the Series A Preferred Units on certain rights of the holders of common units are incorporated into this Item 3.03 by reference.

        Item 5.03 Amendments to Articles of Incorporation or Bylaws; Change in Fiscal Year.

        The disclosures under Item 1.01 of this Part 9B relating to our Private Placement and the execution of the Second Amended and Restated Agreement of Limited Partnership are incorporated into this Item 5.03 by reference.

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PART III

        

Item 10.    Directors, Executive Officers and Corporate Governance

Management of Southcross Energy Partners, L.P.

        Southcross Energy Partners, L.P. (the "Partnership," "Southcross," the "Company," "we," "our," or "us") is managed by the directors and executive officers of our General Partner, Southcross Energy Partners GP, LLC ("General Partner"). Our General Partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. Southcross Energy LLC owns all of the membership interests in our General Partner. Our General Partner has a board of directors, and our unitholders are not entitled to elect the directors or to directly or indirectly participate in our management or operations. Our General Partner will be liable, as General Partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our General Partner.

Director Independence

        Although most companies listed on the New York Stock Exchange ("NYSE") are required to have a majority of independent directors serving on the board of directors of the listed company, the NYSE does not require a listed publicly traded master limited partnership like us to have a majority of independent directors on the board of directors of its general partner.

Committees of the Board of Directors

        The board of directors of our General Partner has an Audit Committee, a Conflicts Committee and a Compensation Committee and may have any such other committee as the board of directors shall determine from time to time. Each of the standing committees of the board of directors of our General Partner has the composition and responsibilities described below.

Conflicts Committee

        Jerry W. Pinkerton and Bruce A. Williamson serve as the members of our Conflicts Committee. Mr. Pinkerton serves as the chairman of the Conflicts Committee. Our partnership agreement provides that the Conflicts Committee, as delegated by the board of directors of our General Partner as circumstances warrant, will review conflicts of interest between us and our General Partner or between us and affiliates of our General Partner. If a matter is submitted to the Conflicts Committee for its review and approval, the Conflicts Committee will determine if the resolution of a conflict of interest that has been presented to it by the board of directors of our General Partner is fair and reasonable to us. The current members of the Conflicts Committee and any future members may not be executive officers or employees of our General Partner or directors, executive officers or employees of its affiliates and must comply with the independence and experience standards established by the NYSE and the Securities Exchange Act of 1934 ("Exchange Act") for service on an audit committee of a board of directors. Any matters approved by the Conflicts Committee will be conclusively deemed to have been approved in good faith, to be fair and reasonable to us, approved by all of our partners and not a breach by our General Partner of any duties it may owe us or our unitholders.

Audit Committee

        Jerry W. Pinkerton, Ronald G. Steinhart and Bruce A. Williamson serve as the members of the Audit Committee. Mr. Pinkerton serves as the chairman of the Audit Committee and complies with the independence and experience standards established by the NYSE and Exchange Act for service on an audit committee of a board of directors. The Audit Committee oversees, reviews, acts on and reports

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on various auditing and accounting matters to the board of directors of our General Partner, including: (i) the selection of our independent accountants, (ii) the scope of our annual audits, (iii) fees to be paid to the independent accountants, (iv) the performance of our independent accountants and (v) our accounting practices. In addition, the Audit Committee oversees our compliance programs relating to legal and regulatory requirements. Our General Partner has relied on the phase-in rules of the SEC and the NYSE with respect to the independence of the Audit Committee. Those rules permit our General Partner to have an Audit Committee that has a majority of independent members within 90 days of the effectiveness of the registration statement filed in connection with our initial public offering on November 7, 2012 ("IPO") and all independent members within one year thereafter. In compliance with those rules, on January 16, 2013, Samuel P. Bartlett resigned from the Audit Committee, and Mr. Steinhart was elected to the board of directors of our General Partner and appointed to serve on the Audit Committee and Mr. Biotti resigned from the Audit Committee with the election of Mr. Williamson to the board of directors of our General Partner and appointment to the Audit Committee on April 1, 2013. Messrs. Steinhart and Williamson comply with the independence and experience standards established by the NYSE and the Exchange Act for service on an audit committee of a board of directors. Our General Partner is generally required to have at least three independent directors serving on its board at all times.

Compensation Committee

        Jon M. Biotti, Ronald G. Steinhart and Bruce A. Williamson serve as the members of the Compensation Committee. Mr. Biotti serves as the chairman of the Compensation Committee. On January 16, 2013, Jerry W. Pinkerton resigned from the Compensation Committee, and Mr. Steinhart was elected to the board of directors of our General Partner and appointed to serve on the Compensation Committee. On April 1, 2013, Kim G. Davis resigned from the Compensation Committee, and Mr. Williamson was elected to the board of directors of our General Partner and appointed to serve on the Compensation Committee. The Compensation Committee establishes salaries, incentive compensation and other forms of compensation for officers, non-executive directors and other employees, as well as administers our incentive compensation and benefit plans.

Directors and Executive Officers

        Directors are appointed for a term of one year and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Officers

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serve at the discretion of the board of directors. The following table shows information for the directors and executive officers of our General Partner.

Name
  Age   Position with Southcross Energy Partners GP, LLC

David W. Biegler

     66   Chairman of the Board, President, and Chief Executive Officer

Michael T. Hunter

     63   Vice Chairman and Chief Commercial Officer

J. Michael Anderson

     50   Senior Vice President and Chief Financial Officer

David M. Mueller

     55   Senior Vice President and Chief Accounting Officer

Albert B. Glasgow

     61   Senior Vice President, Operations

Ronald J. Barcroft

     68   Senior Vice President, Natural Gas Liquids

Samuel P. Bartlett

     40   Director

Jon M. Biotti

     44   Director

Kim G. Davis

     56   Director

Jerry W. Pinkerton

     72   Director

Ronald G. Steinhart

     72   Director

Bruce A. Williamson

     53   Director

        David W. Biegler was elected Chairman of the board of directors and Chief Executive Officer of our General Partner in August 2011 and was elected President in October 2012. Since July 2009, Mr. Biegler served as chairman of the board of directors and chief executive officer of Southcross Energy LLC, our predecessor. Mr. Biegler has 46 years of experience in the energy industry, having held various management positions in upstream, midstream, downstream and oilfield services companies. From 2004 until 2012, Mr. Biegler served as chairman and chief executive officer of Estrella Energy LP, an entity formed for the purpose of acquiring midstream companies, which was a founding investor in our predecessor. From 2002 to 2004, Mr. Biegler was the chairman of the board of Regency Gas Services, a midstream company that he co-founded and that was ultimately sold to a private equity firm. Mr. Biegler retired as vice chairman of the board of TXU Corp. (now Energy Future Holdings Corp.) in 2001, a position he assumed earlier that year. From 1997 to 2001, he served as president and chief operating officer of TXU Corp., the result of a merger between Texas Utilities and ENSERCH Corporation. From 1966 to 1997, Mr. Biegler held various management positions at ENSERCH Corporation and its upstream, midstream, downstream and oilfield field services subsidiaries, including as ENSERCH's chairman, president and chief executive officer from 1994 to 1997.

        Mr. Biegler serves as a director of Southwest Airlines Co. and Trinity Industries, Inc. He previously served as a director of Dynegy, Inc., Guaranty Financial Group, and Animal Health International, Inc. Mr. Biegler received a Bachelor of Science degree in physics from St. Mary's University and is a graduate of Harvard University's advanced management program. He has served as a member of the National Petroleum Council and as the chairman of the American Gas Association, the Southern Gas Association, the American Gas Foundation and the Texas Pipeline Association.

        Michael T. Hunter was appointed Vice Chairman and Chief Commercial Officer of our General Partner in October 2012. From August 2011 to October 2012, Mr. Hunter served as President of our General Partner. Since July 2009, Mr. Hunter served as president and a member of the board of directors of Southcross Energy LLC, our predecessor. Mr. Hunter has 36 years of experience in the energy industry, having held various management and board positions in several energy companies.

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From 2004 until 2012, Mr. Hunter served as president of Estrella Energy LP, an entity formed for the purpose of acquiring midstream companies, which was a founding investor in our Southcross Energy LLC.

        Mr. Hunter serves as the vice chairman of the Texas Energy Reliability Council and has served as a member of the board of directors or as a trustee for the Southern Gas Association, Texas Pipeline Association, Gas Research Institute and Institute of Gas Technology. He is also a member of the board of directors for the University of Idaho Foundation. Mr. Hunter received a Bachelor of Science degree in political science and a Master's degree in business administration from the University of Idaho.

        J. Michael Anderson was appointed Senior Vice President and Chief Financial Officer of our General Partner in April 2012. Mr. Anderson was the Senior Vice President and Chief Financial Officer of Exterran GP LLC, the general partner of Exterran Partners, L.P., from November 2011 until he joined our General Partner. Prior to that, Mr. Anderson had served as Senior Vice President of Exterran GP LLC since June 2006 and as a director of Exterran GP LLC since October 2006. He also served as Senior Vice President and Chief Financial Officer of Exterran Holdings, Inc. from August 2007 to December 2011. Prior to the merger of Hanover Compressor Company and Universal Compression Holdings Inc. in August 2007, Mr. Anderson was Senior Vice President and Chief Financial Officer of Universal, a position he assumed in March 2003.

        Mr. Anderson holds a BBA in finance from Texas Tech University and an MBA in finance from The Wharton School of the University of Pennsylvania.

        David M. Mueller was appointed Senior Vice President and Chief Accounting Officer of our General Partner in April 2012. From August 2011 to April 2012, Mr. Mueller served as Senior Vice President, Finance and Administration of our General Partner. From July 2009 to August 2011, Mr. Mueller served as Senior Vice President, Finance and Administration of Southcross Energy LLC, our predecessor.

        Mr. Mueller has 33 years of financial and operational experience in the energy industry. Prior to joining Southcross Energy LLC, Mr. Mueller served as vice president, finance and controller of PSEG Texas (f/k/a Texas Independent Energy), an independent power producer and subsidiary of Public Service Enterprise Group Incorporated, from July 1999 to December 2008. From December 2008 until joining Southcross Energy LLC in July 2009, Mr. Mueller consulted for PSEG Texas, assisting in the management and orderly retirement of the company's long-term debt.

        Mr. Mueller received a BBA in accounting from Texas Tech University. He is a member of the American Institute of Certified Public Accountants and Financial Executives International.

        Albert B. Glasgow was appointed Senior Vice President, Operations of our General Partner in August 2011. Since 2009, Mr. Glasgow served as Senior Vice President, Operations of Southcross Energy LLC, our predecessor. Mr. Glasgow has 39 years of experience in the energy industry. Prior to joining Southcross Energy LLC, he served as vice president of operations for the western division of Duke Energy Field Services, LLC, a joint venture between Phillips Petroleum (now ConocoPhillips Company) and Duke Energy Corporation from April 2000 to March 2005.

        Mr. Glasgow received a Bachelor of Mechanical Engineering degree from Texas A&M University in 1973 and is a registered professional engineer in the states of Oklahoma and Texas. Mr. Glasgow is active in the Gas Processors Association, having served as a regional program committee member,

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Permian Basin Chapter President for three terms, and co-chairman of the maintenance and operations section for the national organization.

        Ronald J. Barcroft was appointed Senior Vice President, Natural Gas Liquids of our General Partner in October 2012. From August 2011 to October 2012, Mr. Barcroft served as Senior Vice President, Business Development of our General Partner. From July 2009 to August 2011, Mr. Barcroft served as Senior Vice President, Commercial of Southcross Energy LLC, our predecessor. Mr. Barcroft has 43 years of experience in the energy industry in the U.S. and Canada. From 2005 until 2012, Mr. Barcroft served as Senior Vice President of Estrella Energy LP, an entity formed for the purpose of acquiring midstream companies, which was a founding investor in our predecessor. In 2005, he retired as vice president of Duke Energy Field Services, LLC, where he was responsible for the Western Division's commercial and business development activities.

        Mr. Barcroft received a Bachelor's of Applied Science in chemical engineering in 1969 from the University of Waterloo, Ontario. Prior to leaving Canada, Mr. Barcroft was a registered engineer in Quebec and Alberta. He has served on the board of the Gas Processors Association, Oklahoma region, and on various Gas Processors Association regional committees.

        Mr. Bartlett has served as a director of our General Partner since April 2012 and was appointed to the board in connection with his affiliation with Charlesbank, which controls our General Partner. Mr. Bartlett is a Managing Director of Charlesbank, a private investment firm located in Boston, Massachusetts, with an office in New York. Prior to joining Charlesbank in 1999, he was employed by Bain & Company, where he worked in the private equity and general practice areas. Mr. Bartlett serves as a director of CIFC Corp. In addition, Mr. Bartlett serves on the board of directors of a privately held Charlesbank portfolio company. Mr. Bartlett received a BA, magna cum laude, from Amherst College. Mr. Bartlett was selected to serve as a director on the board due to his affiliation with Charlesbank, his knowledge of the energy industry and his financial and business expertise.

        Mr. Biotti has served as a director of our General Partner since April 2012 and was appointed to the board in connection with his affiliation with Charlesbank, which controls our General Partner. In addition, Mr. Biotti serves as the Chairman of the Compensation Committee of the board of directors of our General Partner. Mr. Biotti is a Managing Director of Charlesbank, which he joined in 1998. Mr. Biotti serves as a director of Blueknight Energy Partners G.P., L.L.C., the General Partner of Blueknight Energy Partners, L.P., a publicly traded master limited partnership that provides integrated terminalling, storage, processing, gathering and transportation services for companies engaged in the production, distribution and marketing of crude oil and asphalt products. Mr. Biotti serves on the board of directors of several privately held Charlesbank portfolio companies. Mr. Biotti was also a board member of Regency Gas Services, representing Charlesbank which was Regency's founding equity investor. Educated at Harvard, Mr. Biotti received a Bachelor's degree in government and sociology, an MBA and an MA in public administration. Mr. Biotti was selected to serve as a director on the board due to his affiliation with Charlesbank, his knowledge of the energy industry and his financial and business expertise.

        Mr. Davis has served as a director of our General Partner since April 2012 and was appointed to the board in connection with his affiliation with Charlesbank, which controls our General Partner.

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Mr. Davis is a Managing Director and founding partner of Charlesbank. Prior to co-founding Charlesbank in July 1998, he was a Managing Director of its predecessor firm, Harvard Private Capital Group. Previously, Mr. Davis was at Kohlberg & Co. as General Partner, at Weiss, Peck & Greer as Partner, and at General Motors and Dyson-Kissner-Moran in various positions. Mr. Davis serves on the board of directors of several privately held Charlesbank portfolio companies. Mr. Davis was also a board member of Regency Gas Services, representing Charlesbank which was Regency's founding equity investor. He graduated from Harvard University with a BA in history and also holds an MBA from Harvard. Mr. Davis was selected to serve as a director on the board due to his affiliation with Charlesbank, his knowledge of the energy industry and his financial and business expertise.

        Jerry W. Pinkerton was appointed as an independent member of the board of directors of our General Partner in April 2012. In addition, Mr. Pinkerton serves as Chairman of the Audit Committee and Chairman of the Conflicts Committee of the board of directors of our General Partner. With respect to the Audit Committee, Mr. Pinkerton qualifies as an "audit committee financial expert." Mr. Pinkerton has over 50 years of management, finance and accounting experience and has held various positions in several publicly traded companies. Mr. Pinkerton has served on the board of directors and as chairman of the audit committee of Holly Energy Partners, L.P. since July 2004. From December 2000 to December 2003, Mr. Pinkerton served as a consultant to TXU Corp. (now Energy Future Holdings Corp.), and, from August 1997 to December 2000, he served as Controller of TXU Corp. and its U.S. subsidiaries. From August 1988 until its merger with TXU Corp. in August 1997, Mr. Pinkerton served as the Vice President and Chief Accounting Officer of ENSERCH Corporation. Prior to joining ENSERCH in August 1988, Mr. Pinkerton was employed for 26 years as an auditor by Deloitte Haskins & Sells, a predecessor firm of Deloitte & Touche, LLP, including 15 years as an audit partner. From May 2008 to June 2011, Mr. Pinkerton also served on the board of directors of Animal Health International, Inc., where he also served as chairman of its audit committee.

        The members of our General Partner appointed Mr. Pinkerton to serve as a director due to his audit, accounting and financial reporting expertise and knowledge that qualifies him as a financial expert for his role as the chairman of the audit committee. Due to his executive managerial experience with public companies and public accounting firms and his prior board service, including audit committee experience, Mr. Pinkerton possesses business and management expertise and a broad range of expertise and knowledge of board committee functions. Mr. Pinkerton received his Bachelor of Business Administration degree in Accounting from The University of North Texas.

        Ronald G. Steinhart was elected as an independent member of the board of directors of our General Partner in January 2013. In addition, Mr. Steinhart serves as a member of the Audit Committee and the Compensation Committee of the board of directors of our General Partner. With respect to the Audit Committee, Mr. Steinhart qualifies as an "audit committee financial expert." Mr. Steinhart retired in 2000 as Chairman and Chief Executive Officer of the Commercial Banking Group of Bank One Corporation (commercial banking), a position he had held since 1996. He has over 35 years of experience in the financial services industry. He led a group of investors that established Team Bank (commercial banking) in 1988 and served as its Chairman and Chief Executive Officer until it merged with Bank One Texas in 1992. He was President and Chief Operating Officer of Bank One Texas through 1996. He is also a former President and Chief Operating Officer of InterFirst Corporation (commercial bank holding company), prior to which he teamed with investors to charter or purchase six other banks. He is a current director of Texas Industries, Inc., Penske Automotive Group, Inc. and Susser Holdings Corporation. During the last five years, Mr. Steinhart has been a director of Animal Health International, Inc. and Penson Worldwide, Inc. and has been a trustee of the

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MFS/Compass Group of mutual funds. Mr. Steinhart is an Advisory Board Member of the McCombs School of Business at the University of Texas at Austin. Among the civic positions in which he has served are Chairman of the Board of Trustees of the Teacher Retirement System of Texas, Chairman of the Housing Authority of the City of Dallas, Chairman of the United Way of Metropolitan Dallas, President of the Federal Advisory Council of the Federal Reserve System, Chairman of the Dallas Citizens Council and Regent of the Lamar University System.

        Mr. Steinhart was elected to the board of directors of our General Partner due to his management experience, accounting and financial expertise and knowledge. Due to his executive managerial experience and his prior board service, Mr. Steinhart possesses business and management expertise and a broad range of expertise and knowledge of board committee functions. Mr. Steinhart received his BBA in accounting and his MBA in Finance from the University of Texas in Austin.

        Bruce A. Williamson was elected as an independent member of the board of directors of our General Partner in April 2013. In addition, Mr. Williamson serves as a member of the audit, compensation and conflicts committee of the board of directors of our general partner. Mr. Williamson is currently the President and Chief Executive Officer of Cleco Corporation, an energy services company, and was the Chairman, President and Chief Executive Officer at Dynegy, Inc., from 2002 through 2011. Prior to his role at Dynegy, Inc., Mr. Williamson was the President and Chief Executive Officer at Duke Energy Global Markets. Prior to Duke, Mr Williamson was Senior Vice President Finance at PanEnergy and also worked for Shell Oil Company for 14 years in exploration & production in the US and internationally. Mr. Williamson currently serves on the Board of Questar Corporation, an integrated natural gas company.

        Mr. Williamson was elected to the board of directors of our General Partner due to his extensive expertise in the energy industry. Mr. Williamson received his BS degree in finance from the University of Montana, and his MBA from the University of Houston.

Code of Ethics, Corporate Governance Guidelines and Board Committee Charters

        Our General Partner has adopted a Code of Business Conduct and Ethics, which applies to our General Partner's directors, officers and employees. A waiver of the Code of Business Conduct and Ethics for any director or executive officer of our General Partner may be granted only by the Audit Committee, and such committee will report any such waiver to the board of directors of our General Partner. A waiver of the Code of Business Conduct and Ethics for other officers or employees may be granted only by our Chief Executive Officer, who will thereafter report any such waiver to the Audit Committee. The board of directors of our General Partner has also adopted Corporate Governance Guidelines, which outline the important policies and practices regarding our governance. Jerry W. Pinkerton serves as the lead director, as such term is used in the Corporate Governance Guidelines.

        We make available free of charge, within the "Investors" section of our Internet website at www.southcrossenergy.com, and in print to any unitholder who so requests, the Code of Business Conduct and Ethics, the Corporate Governance Guidelines, the Audit Committee Charter and the Compensation Committee Charter. Requests for print copies may be directed to investorrelations@southcrossenergy.com or to: Investor Relations, Southcross Energy Partners, L.P., 1700 Pacific Avenue, Suite 2900, Dallas, Texas 75201, or telephone (214) 979-3720. We will post on our Internet website all waivers to or amendments of the Code of Business Conduct and Ethics, which are required to be disclosed by applicable law and the NYSE's Corporate Governance Listing Standards. The information contained on, or connected to, our Internet website is not incorporated by reference

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into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the US Securities and Exchange Commission (the "SEC").

Section 16(a) Beneficial Ownership Reporting Compliance

        Section 16(a) of the Exchange Act requires our General Partner's board of directors and executive officers, and persons who own more than 10% of a registered class of our equity securities, to file with the SEC, and any exchange or other system on which such securities are traded or quoted, initial reports of ownership and reports of changes in ownership of our common units and other equity securities. Officers, directors and greater than 10 percent unitholders are required by the SEC's regulations to furnish to us and any exchange or other system on which such securities are traded or quoted with copies of all Section 16(a) forms they file with the SEC.

        To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that all reporting obligations of our General Partner's officers, directors and greater than 10% unitholders under Section 16(a) were satisfied during the year ended December 31, 2012.

Item 11.    Executive Compensation

Executive Compensation Discussion

Overview of our Executive Compensation Program

        This executive compensation discussion describes the compensation policies, programs, material components and decisions of the compensation committee of the board of directors of our General Partner (the "Compensation Committee") with respect to our General Partner's executive officers, including the following individuals who are referred to as the "Named Executive Officers":

        Our compensation practices and programs generally are designed to attract, retain and motivate exceptional leaders and structured to align compensation with the Partnership's overall performance, including growth in distributions to unitholders. The compensation practices and programs have been implemented to promote achievement of short-term and long-term business objectives consistent with the Partnership's strategic plans and are applied to reward performance. To accomplish these objectives, our compensation program consists of the following components: (i) base salary, designed to compensate executive officers for work performed during the fiscal year; (ii) short-term incentive compensation, designed to reward executive officers for the Partnership's yearly performance and for performance specific to executive officers area of responsibility; and (iii) long-term incentive compensation in the form of equity awards, meant to align our Named Executive Officers' interests with the Partnership's long-term performance.

        As a result of the IPO transactions and the conveyance of Southcross Energy LLC's subsidiaries, during the transition period from November 7, 2012 to December 31, 2012 we had 156 employees who provided direct, full-time support to our operations. On January 1, 2013, all employees were transferred to our General Partner. As a result, we do not directly employ any of the persons responsible for managing our business. Our General Partner, under the direction of its board of directors, is responsible for managing our operations and employs all of the employees that operate our business. For 2013, the compensation payable to the officers of our General Partner will be paid by our General Partner and such payments will be reimbursed by us on a dollar-for-dollar basis.

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        References in this report to Named Executive Officers, executive officers, other officers, directors, and employees refer to the Named Executive Officers, executive officers, other officers, directors, and employees of our General Partner.

Role of the Compensation Committee and Management

        Our General Partner is responsible for the management of the Partnership. The Compensation Committee is appointed by the board of directors of our General Partner to assist the board of directors in discharging the board of directors' responsibilities relating to overall compensation matters, including, without limitation, matters relating to compensation programs for our directors and executive officers. The Compensation Committee is directly responsible for the General Partner's compensation programs, which include programs that are designed specifically for our executive officers, including our Named Executive Officers.

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        The Compensation Committee has overall responsibility for evaluating and approving the compensation plans, policies and programs of our General Partner. To that end, the Compensation Committee has the responsibility, power and authority to set the compensation of executive officers, determine grant awards under and administer the General Partner's equity compensation plans, and assume responsibility for all matters related to the foregoing. The Compensation Committee is charged, among other things, with the responsibility of reviewing the executive officer compensation policies and practices for (i) adherence to our compensation philosophy and (ii) ensuring that the total compensation paid to our executive officers is fair, reasonable and competitive. These compensation programs for executive officers consist of base salary, annual incentive bonus and Long-Term Incentive Plan ("LTIP") awards typically in the form of equity-based restricted units and phantom units, as well as other customary employment benefits. Total compensation of executive officers and the relative emphasis of the three main components of compensation are reviewed at least on an annual basis by the Compensation Committee, which then makes recommendations to the board of directors of our General Partner for its approval.

        It is the practice of the Compensation Committee to meet in person or by conference call at least once a year for a number of purposes. These include (i) assessing the performance of the Chief Executive Officer and other executive officers with respect to the Partnership's results for the preceding year, (ii) establishing compensation levels for each executive officer for the ensuing year, (iii) determining the amount of the annual bonus pool approved by the board of directors of our General Partner to be paid to the executive officers after taking into account both the target bonus levels established for those executive officers at the outset of the preceding year and the foregoing performance factors. Our Chief Executive Officer participates in the process of allocating our bonus pool and makes recommendations to the Compensation Committee regarding the amount of bonuses and other compensation paid to executive officers, other than the Chief Executive Officer, and (iv) determining equity awards under the LTIP for executive officers and other key employees.

Compensation Philosophy and Objectives

        The principal objective of our compensation program is to attract and retain, as executive officers and employees, individuals of demonstrated competence, experience and leadership in our industry and in those professions required by our business who share our business aspirations, values, ethics and culture.

        In establishing our compensation programs, we consider the following compensation objectives:

        We also strive to achieve a fair balance between the compensation rewards that we perceive necessary to remain competitive in the marketplace and fundamental fairness to our unitholders, taking into account the return on their investment.

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        In measuring the contributions of our executive officers to the performance of the Partnership for 2012, the Compensation Committee considered and utilized the following financial and operating performance factors:

Compensation Methodology

        The Compensation Committee intends to review annually our executive compensation program in total and each element of compensation specifically. The Compensation Committee intends to include the following in its periodic review of our executive compensation program: (i) an analysis of the compensation practices of other companies in our industry; (ii) the competitive market for executive talent; (iii) the evolving demands of our business; (iv) specific challenges that we may face; and (v) individual contributions to our Partnership. The Compensation Committee will recommend to the board of directors of our General Partner adjustments to the overall executive compensation program, and to its individual components, as the Compensation Committee determines necessary to achieve our goals and comply with the Compensation Committee's compensation philosophy. The Compensation Committee intends to retain compensation consultants periodically, and retained an executive compensation consultant in January 2013, to assist in its review and to provide input regarding our compensation program and each of its elements.

        In addition, the Compensation Committee intends to review various relevant compensation surveys with respect to determining compensation for the Named Executive Officers. In determining the long-term incentive compensation of executive officers (including the Named Executive Officers), the Compensation Committee will consider individual performance, the relative value of the equity holder's beneficial ownership, the value of similar incentive awards to executive officers at comparable companies, prior equity awards made to the Partnership's executive officers in past years, the value of all unvested awards held by the executive and such other factors as the Compensation Committee deems relevant.

Market Analysis

        In January 2013, to ensure that our executive compensation practices remain competitive, the Compensation Committee retained BDO Seidman, LLP, a compensation consulting firm, to provide a comparative compensation analysis for our executive officers and certain key employees. The Compensation Committee selected a peer group that includes the 13 publicly-traded limited partnerships listed below, which are in the midstream market segment of our industry. In selecting this peer group, we considered those of our competitors that are of a size similar to our own, measured by

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market capitalization. Our market capitalization falls in the median to lower range of the peer group, which consists of the following companies:

Atlas Pipeline Partners, L.P.   Magellan Midstream Partners, L.P.

Boardwalk Pipeline Partners, LP
 
MarkWest Energy Partners, L.P.

Copano Energy, L.L.C.
 
Martin Midstream Partners L.P.

Crestwood Midstream Partners, LP
 
Plains All American Pipeline, L.P.

Crosstex Energy, L.P.
 
Regency Energy Partners, LP

DCP Midstream Partners, LP
 
Targa Resources Partners LP

Eagle Rock Energy Partners, L.P.
 
 

        In addition to our peer group, we also intend to rely on the expertise of BDO Seidman, LLP in order to obtain a more complete picture of the overall compensation environment. The Compensation Committee has determined that no conflicts of interest exist with respect to any work performed for us by BDO Seidman, LLP.

        When considering comparative data, the Compensation Committee generally intends to position the total compensation of our Named Executive Officers at the median range by reference to persons with similar duties at our peer group companies. The Compensation Committee also seeks to reward our executive officers when the Partnership exceeds its performance goals by providing compensation that approximates the upper quartile of our peer group. However, actual compensation decisions for individual officers are the result of the Compensation Committee's subjective analysis of a number of factors, including the individual officer's experience, skills or tenure with us, changes to the individual's position, or trends in compensation practices within our peer group or industry. Each executive's current and prior compensation is considered in setting future compensation. The amount of each executive's current compensation is considered as a base-line against which the Compensation Committee makes determinations as to whether adjustments are necessary to retain the executive in light of competition or in order to provide continuing performance incentives. Thus, the Compensation Committee's determinations regarding compensation are the result of the exercise of judgment based on all reasonably available information and, to that extent, are discretionary. The Compensation Committee may use its discretion to adjust any of the components of compensation to achieve our goal of attracting and retaining individuals with the skills necessary to execute our business strategy and to develop and grow our business.

Elements of our Compensation Programs

        Compensation for our Named Executive Officers consists primarily of the elements, and their corresponding objectives, identified in the following table:

Compensation Element   Characteristics   Primary Objectives
Base salary   Fixed annual cash compensation. Salaries may be increased periodically based on performance or other factors.   Recognize performance of job responsibilities and attract and retain individuals with superior talent.

Annual performance-based compensation
 
Performance-related annual cash incentives earned based on financial and other objectives.
 
Promote near-term performance objectives and reward individual contributions for the achievement of those objectives.

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Compensation Element   Characteristics   Primary Objectives
Long-term equity participation   Equity awards purchased or granted subject to time and/or performance based vesting restrictions intended to align indirect ownership interests of Named Executive Officers with unitholder interests.   Emphasize long-term performance objectives, encourage the maximization of unitholder value and retain key executives by providing an opportunity to participate in the ownership of Southcross Energy LLC. Vesting restrictions are designed to facilitate Named Executive Officer retention and to provide continuing performance incentives.

Severance and change in control benefits
 
Severance agreements provide for twelve or twenty-four months of base salary and benefit continuation in the event of certain involuntary terminations of employment. A portion of the Named Executive Officers' equity incentives are subject to accelerated change in control vesting.
 
Encourage the continued attention and dedication of our Named Executive Officers and focus the attention of them when considering strategic alternatives.

Retirement savings 401(k) plan
 
Qualified 401(k) retirement plan benefits are available for our Named Executive Officers, other executive officers, and all other regular full-time employees. For 2012, we matched employee contributions to 401(k) plan accounts up to a maximum employer contribution of 6% of the employee's eligible compensation.
 
Provide an opportunity for tax-efficient savings.

Health and welfare benefits
 
Health and welfare benefits (medical, dental, vision, disability insurance and life insurance) are available for our executive officers and all other regular full-time employees.
 
Provide benefits to meet the health and wellness needs of our executive officers and other employees and their families.

Compensation Components and Analysis

        Base Salary.    We believe that executive officer base salaries should be competitive with salaries for executive officers in similar positions with similar responsibilities in our marketplace. Base salaries for our Named Executive Officers were set at initially modest levels, due primarily to our limited operating history at the time such salaries were determined and in order to limit fixed administrative costs during our initial period of operations. We set those base salaries with the expectation that the base salaries would be increased over time to bring them closer to competitive levels of base salaries in our industry,

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as the complexity and scope of our business increased. Effective March 2012, Messrs. Biegler and Hunter each received base salary increases of 60.0% and 7.1%, respectively; these increases were made to reflect the increased scope of these Named Executive Officers' respective positions as the Partnership continues to grow and mature and, with respect to Mr. Biegler, to reflect an increase from 60% to 100% to correspond with the amount of time he devotes to the Partnership. Mr. Anderson, our Chief Financial Officer, joined the Partnership on April 2, 2012 at an annualized base salary reflected in the table below.

        The annualized base salaries as of December 31, 2012 for our Named Executive Officers are set forth in the following table:

Name and principal position   Base salary  

David W. Biegler

   $ 400,000  

Chairman, President and Chief Executive Officer

        

Michael T. Hunter

   $ 300,000  

Vice Chairman and Chief Commercial Officer

        

J. Michael Anderson

   $ 275,000  

Senior Vice President and Chief Financial Officer

        

        Going forward, base salaries for our Named Executive Officers will continue to be reviewed periodically by the Compensation Committee, with adjustments expected to be made generally in accordance with the considerations described above and to maintain base salaries at competitive levels.

        Annual Performance-Based Compensation for 2012.    Each of our Named Executive Officers participates in an incentive bonus compensation program under which incentive awards are determined annually, with target bonus levels historically having been set at 40% of annualized base salary for Messrs. Biegler and Hunter. Mr. Anderson, who joined the Partnership in 2012, has a target bonus level equal to 60% of his annualized base salary. Prior to 2012, annual incentive bonuses for our executive officers were determined based on the achievement of pre-established financial and operational performance criteria, including our level of achievement against a range of total EBITDA targets. In early 2012, due to the expected variability of income associated with our large expansion projects (including the construction of our new Woodsboro Processing Plant and Bonnie View NGL Fractionation Plant), we determined not to establish formal EBITDA targets or other financial and operational performance measures with respect to our 2012 annual incentive compensation program. Instead, we determined that 2012 annual incentive bonus awards for our Named Executive Officers would be determined by the board of directors of our General Partner in its discretion following the completion of the 2012 fiscal year, based upon factors such as the satisfactory execution of our recapitalization strategy and growth plans, completion of the construction of our new Woodsboro Processing Plant and Bonnie View NGL Fractionation Plant, capital expenditure and operating expense performance, increase in new gas supply contracts, and each individual's contributions to our overall success during the year. For 2012, the board of directors of our General Partner determined not to award a bonus to Messrs. Biegler and Hunter.

        For Mr. Anderson's service in 2012, the board of directors of our General Partner awarded him a bonus equal to 100% of his target bonus amount (which is 60% of his 2012 pro-rated annualized base salary) per the terms of Mr. Anderson's employment offer. The actual bonus amount awarded to Mr. Anderson for 2012 is set forth below in the Summary Compensation Table. Effective for annual incentive bonus compensation that may be paid for performance in 2013 and thereafter, to reflect the increased scope of duties in relation to our operation as a publicly traded master limited partnership, the board of directors of our General Partner increased the target bonus amounts for Messrs. Biegler and Hunter to 100% of his 2013 annualized base salary and 60% of his annualized base salary, respectively.

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        Benefit Plans and Perquisites.    We provide our executive officers, including our Named Executive Officers, with a standard complement of health and retirement benefits under the same plans as all other employees, including medical, dental and vision benefits, disability and life insurance coverage, and a defined contribution plan that is tax-qualified under Section 401(k) of the Internal Revenue Code ("401(k) Plan"). We believe that our health benefits provide stability to our Named Executive Officers, thus enabling them to better focus on their work responsibilities, while our 401(k) Plan provides a vehicle for tax-preferred retirement savings with additional compensation in the form of an employer match that adds to the overall desirability of our executive compensation package. For 2012, we provided an employer match under the 401(k) plan equal to 100% of employee contributions up to 6% of base salary. In 2012, none of our executive officers, including our Named Executive Officers, received any personal benefits or perquisites that were not made generally available to all of our salaried employees on a non-discriminatory basis. In addition, none of our Named Executive Officers participated in any defined benefit pension plans or non-qualified deferred compensation plans.

        Severance Agreements and Change in Control Provisions.    We maintain severance and other compensatory agreements with some of our executive officers for a variety of reasons, including the fact that severance agreements can be an important recruiting tool in the market in which we compete for talent. Certain provisions in these agreements, such as confidentiality, non-solicitation, and non-compete clauses, protect the Partnership and its unitholders after the termination of the employment relationship. We believe that it is appropriate to compensate former executives for these post-termination agreements, and that compensation helps to enhance the enforceability of these arrangements. These agreements are described in more detail elsewhere in this report.

        Recoupment Policy.    Equity awards granted under the LTIP are subject to recovery, including modification and forfeiture, for certain "Acts of Misconduct" defined in the LTIP. We currently do not have a recovery policy applicable to annual cash incentive bonuses. The Compensation Committee will continue to evaluate the need to amend such a policy, in light of current legislative policies, economic and market conditions.

Compensation Committee Report

        The Compensation Committee issued the following report:

        We have reviewed and discussed with management certain compensation discussion provisions to be included in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2012 to be filed pursuant to Section 13(a) of the Securities and Exchange Act of 1934 (the "Annual Report"). Based on those reviews and discussions, we recommend to the Board of Directors of the General Partner that the Executive Compensation Discussion be included in the Annual Report.


Compensation Committee

Jon M. Biotti, Chairman
Kim G. Davis
Ronald G. Steinhart

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Summary Compensation Table

        The following table (the "Summary Compensation Table") sets forth certain information with respect to the compensation paid to our Named Executive Officers for the years ended December 31, 2011 and 2012:

Name and Principal Position
  Year   Salary ($)   Stock
awards
($)(1) 		  Non equity
incentive plan
compensation
($)(2) 		  Bonus
($) 		  All other
compensation
($)(3) 		  Total
($) 		 
David W. Biegler     2012     360,577     —     —     —     16,615     377,192  

Chairman, President and Chief

     2011     232,500     —     60,000     —     —     292,500  

Executive Officer

                                            
Michael T. Hunter     2012     290,000     —     —     —     17,000     307,000  

Vice Chairman and Chief

     2011     275,385     —     67,200     —     14,700     357,285  

Commercial Officer

                                            
J. Michael Anderson     2012     200,962     1,755,000     —     120,577     35,164     2,111,703  

Senior Vice President and Chief

     2011     _     —     —     —     —     —  

Financial Officer

                                            
(1)
Represents the grant date fair value of Mr. Anderson's equity equivalent units, as determined in accordance with FASB ASC Topic 718, and is based on an estimate of the value of one common unit holdings of $117.00 as of such date.

(2)
Represents awards earned under our annual incentive bonus program. For a discussion of the determination of these amounts see "Annual Performance Based Compensation for 2012".

(3)
Represents employer contributions under the 401(k) Plan for Messrs. Biegler, Hunter and Anderson. Mr. Anderson's amount also includes $31,356 of reimbursement for 2012 interim living expenses.

        A discussion of the material compensation information disclosed in the Summary Compensation Table is set forth in the "Compensation Components and Analysis" section above.

        The following is a discussion of other material factors necessary to understanding total compensation afforded to our Named Executive Officers:

        Long-Term Equity Incentive Units.    In August 2009, in connection with the formation of Southcross Energy LLC, Messrs. Biegler and Hunter were allowed to purchase equity interests in Southcross Energy LLC, pursuant to subscription agreements entered into by such persons with Southcross Energy LLC. The purchase price paid for the units was the same price paid per unit by Charlesbank. A portion of the units purchased by Messrs. Biegler and Hunter, which portion we refer to as the incentive units, are subject to vesting restrictions and were intended as equity incentives to promote long-term compensation objectives and provide them with meaningful incentives to increase unitholder value over time. Twenty-two percent (22%) of these incentive units are tied to time-based vesting requirements and seventy-eight percent (78%) are tied to performance-based vesting conditions. The units subject to time-based vesting requirements vest in five cumulative annual installments, twenty percent (20%) of the relevant units on each anniversary of the grant date, and are subject to the requirement of continued employment through the applicable vesting date. Generally, the time vesting incentive units are designed to compensate, motivate and retain the recipients by subjecting such equity ownership to continued service requirements.

        The performance-based vesting incentive units are intended to motivate Messrs. Biegler and Hunter and to reward the financial success of Southcross Energy LLC, which, following the consummation of our IPO, are tied directly to our financial success. The units held by them will vest, if at all, only upon the occurrence of a transaction that results in Charlesbank receiving cash or liquid securities in an amount that results in Charlesbank achieving certain investment multiples and internal rates of return with respect to its investment in Southcross Energy LLC. A portion of the

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performance-based vesting units vest upon the occurrence of such a transaction that results in Charlesbank achieving an investment multiple reflecting a return of 2.0 times invested capital and an internal rate of return of 20%, and the remainder of such units vest cumulatively based on the occurrence of a transaction that results in Charlesbank achieving investment multiples and internal rates of return over and above these threshold amounts. The units will be fully vested upon the occurrence of a transaction that results in Charlesbank achieving an investment multiple reflecting a return of 3.5 times invested capital and an internal rate of return of 35%. The performance-based vesting units are also subject to the requirement of continued employment through the applicable vesting date. The consummation of our IPO did not constitute a liquidity event for purposes of the performance-based incentive units. Upon a Named Executive Officer's termination of employment, any unvested incentive units are subject to repurchase rights by Southcross Energy LLC at the Named Executive Officer's initial acquisition cost of the units (or less in certain circumstances). See "Severance and Change in Control Benefits" below for a description of the circumstances under which vesting of the incentive units may be accelerated.

        Messrs. Biegler and Hunter did not receive any equity incentive units in 2012. In connection with his commencement of employment on April 2, 2012, Mr. Anderson, our Chief Financial Officer, received 15,000 equity equivalent units, as described in more detail below. Going forward, we expect to use equity-based incentives more regularly and that equity-based awards will become more prominent in our annual compensation decision-making process. In connection with our IPO, we adopted the LTIP, which is discussed in more detail under "LTIP" below, and subsequently made awards under it.

        Mr. Anderson's Equity Equivalent Units.    In connection with his commencement of employment, the board of directors of our General Partner determined to grant an equity incentive award to Mr. Anderson to provide him with meaningful incentives to increase unitholder value over time. Mr. Anderson was granted 15,000 equity equivalent units, each of which is intended to be equivalent in value to one incentive unit of the type previously purchased by our Named Executive Officers. These units vest in three cumulative annual installments, one-third of the units on each anniversary of the grant date, subject to continued employment through the applicable vesting date. Upon Mr. Anderson's termination of employment without cause or for good reason or generally upon a change in control, any unvested units will vest in full. Generally, if Mr. Anderson's employment is terminated without cause or Mr. Anderson resigns for good reason or we incur or Southcross Energy LLC incurs a change in control, Mr. Anderson will be entitled to receive for each vested equity equivalent unit a cash payment equal to the value of one incentive unit in Southcross Energy LLC.

        Long-Term Incentive Plan.    In connection with our IPO, our General Partner adopted the Long-Term Incentive Plan (the "LTIP"), pursuant to which our eligible officers, employees and directors are eligible to receive awards with respect to our equity interests, thereby linking the recipients' compensation directly to our performance. The description of the LTIP set forth below is a summary of the material features of the LTIP. This summary does not purport to be a complete description of all of the provisions of the LTIP.

        The LTIP provides for the grant, from time to time at the discretion of the board of directors of our General Partner or Compensation Committee, of restricted units, phantom units, unit options, distribution equivalent rights and other unit-based awards. Subject to adjustment in the event of certain transactions or changes in capitalization, an aggregate of 1,750,000 common units may be delivered pursuant to awards under the LTIP. Units that are cancelled or forfeited will be available for delivery pursuant to other awards. The LTIP is administered by the board of directors of our General Partner, though such administration function may be delegated to a committee (including the Compensation Committee) that may be appointed by the board of directors of our General Partner to administer the LTIP. The LTIP is designed to promote our interests, as well as the interests of our unitholders, by rewarding our directors, officers and employees for delivering desired performance results, as well as by

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strengthening our ability to attract, retain and motivate qualified individuals to serve as our directors, officers and employees.

        Restricted Units and Phantom Units.    A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. The administrator of the LTIP may make grants of restricted and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the administrator may determine are appropriate, including the period over which restricted or phantom units will vest. The administrator of the LTIP may, in its discretion, base vesting on the grantee's completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement.

        Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units. The administrator of the LTIP, in its discretion, may also grant tandem distribution equivalent rights with respect to phantom units. Distribution equivalent rights are rights to receive an amount equal to all or a portion of the cash distributions made on units during the period a phantom unit remains outstanding.

        Unit Options.    The LTIP also permits the grant of options covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit options may be granted to such eligible individuals and with such terms as the administrator of the LTIP may determine, consistent with the LTIP; however, a unit option must have an exercise price equal to at least the fair market value of a common unit on the date of grant.

        Other Unit-Based Awards.    The LTIP also permits the grant of "other unit-based awards," which are awards that, in whole or in part, are valued or based on or related to the value of a unit.

        The vesting of an other unit-based award may be based on a participant's continued service, the achievement of performance criteria or other measures. On vesting or on a deferred basis upon specified future dates or events, an other unit-based award may be paid in cash and/or in units (including restricted units), as the administrator of the LTIP may determine.

        Source of Common Units; Cost.    Common units to be delivered with respect to awards may be newly-issued units, common units acquired by us or our General Partner in the open market, common units already owned by our General Partner or us, common units acquired by our General Partner directly from us or any other person or any combination of the foregoing. With respect to awards made to employees of our General Partner, our General Partner will be entitled to reimbursement by us for the cost incurred in acquiring such common units or, with respect to unit options, for the difference between the cost it incurs in acquiring these common units and the proceeds it receives from an optionee at the time of exercise of an option. Thus, we will bear the cost of all awards under the LTIP. If we issue new common units with respect to these awards, the total number of common units outstanding will increase, and our General Partner will remit the proceeds it receives from a participant, if any, upon exercise of an award to us. With respect to any awards settled in cash by our General Partner, our General Partner will be entitled to reimbursement by us for the amount of the cash settlement.

        Amendment or Termination of LTIP.    The administrator of the LTIP, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The LTIP will automatically terminate on the tenth anniversary of the date it was initially adopted by our General Partner. The administrator of the LTIP also will have the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under

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the LTIP, provided that no change in any outstanding award may be made that would impair materially the vested rights of the participant without the consent of the affected participant, and/or result in taxation to the participant under the Internal Revenue Code Section 409A.

        All Other Compensation.    Please see the "Executive Compensation Discussion" above for a discussion of any perquisites paid to our Named Executive Officers, and the section below entitled "Potential Payments Upon a Termination or Change in Control" for a discussion of payments made upon resignation.

Outstanding Equity Awards at December 31, 2012

        The following table provides information regarding incentive units held by our Named Executive Officers as of December 31, 2012 (in thousands).

 
   Southcross Energy LLC Incentive Units  
Name
  Number of
time-vesting
units that have
not vested(1) 		  Fair value of
time-vesting
units that have
not vested(3) 		  Number of
performance-
vesting units
that have not
vested(2) 		  Fair value of
performance
vesting units that
have not vested(3) 		 

David W. Biegler

     4,869   $ 559.9     43,470   $ 4,999.1  

Michael T. Hunter

     4,869   $ 559.9     43,470   $ 4,999.1  

J. Michael Anderson

     15,000   $ 1,725.0     —   $ —  
(1)
Represents the number of unvested time vesting incentive units purchased on August 6, 2009 by Messrs. Biegler and Hunter. The remaining unvested units held by them vest in two equal annual installments on each of August 6, 2013 and 2014, subject to the recipient's continued employment through the applicable vesting date. With regards to Mr. Anderson, represents the number of unvested time vesting incentive units awarded on April 2, 2012. Units vest in three equal installments on each of April 2, 2013, 2014 and 2015, subject to the recipient's continued employment through the applicable vesting date.

(2)
Represents the number of unvested performance vesting incentive units purchased on August 6, 2009. The units will vest, if at all, upon Charlesbank attaining certain investment multiples and internal rates of return in connection with a liquidity event with respect to its investment in Southcross Energy LLC, subject to the recipient's continued employment through the applicable vesting date. For additional information relating to the performance vesting incentive units, see the discussion above under "Long-Term Equity Incentive Units".

(3)
Amounts shown were calculated based on an estimate of the fair market value of units in Southcross Energy LLC on December 31, 2012.

Potential Payments Upon a Termination or Change in Control

        Severance and Change in Control Benefits.    Our Named Executive Officers are entitled to severance payments and benefits upon certain terminations of employment and, in certain cases, upon a change in control of Southcross Energy LLC. In addition, Mr. Anderson is entitled to severance payments and benefits upon certain qualifying terminations of employment (including in connection with a change in control) and, in certain cases, upon a change in control.

        Each of our Named Executive Officers has entered into a severance agreement with our General Partner that provides for severance benefits upon certain terminations of employment. As described below, these agreements are substantially similar for each of the Named Executive Officers. In addition, pursuant to the severance agreements for Messrs. Biegler and Hunter, described in more detail below, upon termination of employment due to death or disability, Messrs. Biegler and Hunter are entitled to

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accelerated vesting of any unvested time vesting incentive units that would have become vested within one year following the date of the Named Executive Officer's death or disability, as applicable. Mr. Anderson's severance agreement provides for severance payments and benefits upon certain qualifying terminations of employment, as described below.

        Severance Benefits for Messrs. Biegler and Hunter.    Under the severance agreement for Messrs. Biegler and Hunter, upon termination of such executives' employment by us without "cause" or by executive for "good reason" (provided that termination for "good reason" occurs no more than forty-five days following the last event constituting "good reason"), the executive is entitled to receive (i) twelve months of base salary continuation and (ii) company-subsidized group health plan benefits for up to twelve months. Additionally, severance payments are conditioned upon the execution of a general release of claims and continued compliance with certain confidentiality, non-competition and non-solicitation restrictions for six months following termination.

        "Cause" is defined in the severance agreements for Messrs. Biegler and Hunter to mean (i) the executive's indictment for or conviction of, or entering a plea of nolo contendere, to any crime (whether or not a felony) involving dishonesty, fraud, embezzlement, breach of trust or other crime of moral turpitude, (ii) the executive's conviction of, entering a plea of nolo contendere to, a felony (other than a traffic violation), (iii) acts by the executive constituting fraud or willful misconduct in connection with the executive's employment or service relationship, including misappropriation or embezzlement in the performance of the executive's duties, (iv) the executive's failure or willful refusal to perform any of the executive's duties (other than a failure resulting from incapacity due to physical or mental illness) which is reasonably likely to result in material harm to Southcross Energy LLC or its subsidiaries, provided that such failure or refusal is not cured within thirty days of receiving written notice from Southcross Energy LLC, (v) the executive's violation or breach of the ethics provisions of the employee handbook applicable to all employees generally, or the executive's duty of loyalty to Southcross Energy LLC or its affiliates, (vi) the executive willfully or grossly negligently engaging in conduct materially injurious to Southcross Energy LLC or any of its subsidiaries, or (vii) the executive's failure or refusal to devote all of the executive's "business time" to the business and affairs of Southcross Energy LLC and its subsidiaries, provided that such failure or refusal is not cured within thirty days of receiving written notice from Southcross Energy LLC. Generally, "business time" excludes time spent serving on certain corporate, charitable or civic boards or committees, or delivering lectures, fulfilling speaking engagements or teaching at educational institutions.

        "Good reason" is defined in the executives' severance agreements to mean (i) an involuntary reduction in the annual base salary, other than a reduction to which the executive consents or that similarly affects all or substantially all management employees, (ii) a relocation, without the executive's prior written consent, of the geographic location of the executive's principal place of employment by more than twenty-five miles from the executive's principal place of employment as of August 6, 2009, or (iii) the failure of Southcross Energy LLC to pay any cash compensation (such as base salary or bonuses) to the executive when due under the terms of any employment agreement or bonus plan in which the executive is entitled to participate, provided that Southcross Energy LLC has not cured such failure within thirty days of receiving written notice from the executive.

        Change in Control Benefits for Messrs. Biegler and Hunter.    Messrs. Biegler and Hunter are not entitled to any cash payments upon a change in control of us or Southcross Energy LLC. However, pursuant to the subscription agreements relating to the executives' incentive units, the executives' time vesting incentive units will vest in full upon a change in control of Southcross Energy LLC. In addition, upon the occurrence of a liquidity event with respect to Charlesbank's investment in Southcross Energy LLC, which event may also constitute a change in control, the executives' performance vesting incentive units may vest, depending upon the financial outcome of such transaction. For additional information regarding the vesting of the incentive units, see the discussion under "Long-Term Equity

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Incentive Units" above. The consummation of our IPO did not constitute a change in control or liquidity event for purposes of the executives' incentive units.

        Mr. Anderson's Severance and Change in Control Benefits.    Under Mr. Anderson's severance agreement, upon a termination of his employment by us without "cause" or by him for "good reason," in either case, within one year following certain transactions generally resulting in a change in control of Southcross Energy LLC, subject to his execution of a general release of claims, Mr. Anderson will also be entitled to receive (i) an amount equal to two times his annual base salary, (ii) an amount equal to two times his target annual bonus, which is 60% of his base salary, and (iii) reimbursement for the cost of group health plan benefits for eighteen months. In addition, pursuant to Mr. Anderson's offer of employment letter and the award agreement relating to his equity equivalent units, upon a termination of Mr. Anderson's employment without "cause" or for "good reason" or certain transactions generally resulting in a change in control of Southcross Energy LLC or us, any unvested equity equivalent units will vest in full. For additional information regarding the vesting of the equity equivalent units, see the discussion under "Long-term equity incentive units" above. The consummation of our IPO did not constitute a change in control for purposes of Mr. Anderson's equity equivalent units or severance benefits.

        As used in Mr. Anderson's equity equivalent unit award agreement, "cause" and "good reason" have the meanings set forth in our Named Executive Officers' severance agreements, as described above. However, for purposes of Mr. Anderson's severance agreement, "cause" is defined to mean (i) his failure to satisfactorily perform his material duties or to devote his full time and effort to his position, (ii) his violation of any material General Partner policy (provided that such violation is not cured after receiving reasonable notice from our General Partner), (iii) his failure to follow lawful directives from our General Partner's Chief Executive Officer, President or Executive Vice President, the board of directors of our General Partner, or his direct supervisor, (iv) his negligence or material misconduct, (v) his dishonesty or fraud or (vi) his felony conviction.

        In addition, "good reason" is defined in Mr. Anderson's severance agreement to mean (i) a material change in his job duties and responsibilities, (ii) a reduction in his compensation (unless the reduction similarly affects similarly situated employees) or (iii) a change in the location of his regular workplace by more than twenty-five miles.

Potential Payments Upon a Termination or Change in Control Table

        The following table summarizes the change in control and/or severance payments and benefits that each of our Named Executive Officers would have received upon a termination of employment effective as of December 31, 2012 (i) by Southcross Energy LLC without cause, (ii) due to the executive's resignation for good reason or (iii) due to the executive's death or disability. The table also summarizes the value of the vesting acceleration of time vesting incentive units assuming a change in control or liquidity event occurring as of December 31, 2012 and the value of the vesting of performance vesting incentive units assuming a liquidity event occurring with respect to the units effective as of December 31, 2012 (based on the maximum potential amount of performance unit

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vesting), in each case, assuming a unit value as of such date of $115.00 and each Named Executive Officer's base salary in effect as of such date.

Name
  Payment type   Termination
without cause or
due to resignation
for good reason ($) 		  Termination
due to death
or disability
($) 		  Change in
control/liquidity event
(no termination) ($) 		 

David W. Biegler

   Salary(1)     400,000     —     —  

  Benefit continuation     — (3)   —     —  

  Value of time vesting                    

  unit acceleration     —     279,956     559,935  

  Value of performance                    

  unit vesting     —     —     4,999,050  

  Total     400,000     279,956     5,558,985  

Michael T. Hunter

  

Salary(1)

    
300,000		    
—		    
—		  

  Benefit continuation(2)     17,995     —     —  

  Value of time vesting                    

  unit acceleration     —     279,956     559,935  

  Value of performance                    

  unit vesting     —     —     4,999,050  

  Total     317,995     279,956     5,558,985  

J. Michael Anderson

  

Salary(1)

    
880,000		    
—		    
—		  

  Benefit continuation(2)     34,120     —     —  

  Value of time vesting                    

  unit acceleration     1,725,000     —     1,725,000  

  Value of performance                    

  unit vesting     —     —     —  

  Total     2,639,120     —     1,725,000  
(1)
For Messrs. Biegler and Hunter, represents the executive's annual base salary, payable over the one-year period following termination. For Mr. Anderson, represents two times annual base salary plus target bonus, payable within sixty days following termination.

(2)
Consists of continuation of group health benefits. The value of the health benefits was calculated using an estimate of the cost of such health coverage based upon current COBRA plan premium rates.

(3)
Mr. Biegler did not participate in our group health benefit plans as of December 31, 2012.

Director Compensation

        Officers, employees or paid consultants of our General Partner who also serve as directors will not receive additional compensation for their service as directors. On January 16, 2013, the board of directors of our General Partner and the Compensation Committee determined that directors who are not officers, employees or paid consultants of our General Partner will receive a combination of cash and common units to be granted pursuant to the LTIP as compensation for attending meetings of our board of directors of our General Partner and any committees thereof. Specifically, the board and the Compensation Committee approved the following compensation for such directors:

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        Such directors also will receive reimbursement for out-of-pocket expenses associated with attending such board or committee meetings.

        We have adopted the Southcross Energy Partners, L.P. Non-Employee Director Deferred Compensation Plan, pursuant to which non-employee directors of our general partner may elect on an annual basis to defer all earned cash and/or equity compensation until the director is no longer a director of our general partner. All amounts deferred will be converted into phantom units of the Partnership, which will be entitled to receive quarterly distributions of the Partnership. These quarterly distributions will also be converted to phantom units. At the conclusion of the deferral period, the accrued phantom units will be valued at the fair market value of the Partnership's common units as of such date and paid to the director in the form of (i) cash for deferrals of cash compensation and (ii) common units for deferrals of equity compensation. For the calendar year 2013, only Mr. Williamson has elected to defer his non-employee director compensation.

        Each of Messrs. Bartlett, Biotti and Davis have informed us that in accordance with the internal policies of Charlesbank and the terms of the limited partnership agreements for the Charlesbank funds that have invested in Southcross Energy LLC (the "Charlesbank Funds"), that all compensation otherwise payable to any of them as a result of being a director of our General Partner should be paid as follows (i) to the extent the compensation is cash, such compensation should be paid directly to Charlesbank and (ii) in lieu of equity compensation, any such additional compensation should be paid in cash directly to Charlesbank.

Director Compensation for 2012

        The following table presents the cash, equity awards and other compensation earned, paid or awarded to each of our directors during the year ended December 31, 2012:

Name
  Fees earned or
paid in cash 		  Equity awards(3)   Total  

Samuel P. Bartlett(1)

   $ 8,673   $ —   $ 8,673  

Jon M. Biotti(1)

   $ 9,420   $ —   $ 9,420  

Kim G. Davis(1)

   $ 7,473   $ —   $ 7,473  

Jerry W. Pinkerton

   $ 10,541   $ —   $ 10,541  

Ronald G. Steinhart(2)

   $ —   $ —   $ —  

Bruce A. Williamson(2)

   $ —   $ —   $ —  
(1)
Directors associated with Charlesbank. Refer to the section "Director Compensation" above for further information.

(2)
Messrs. Steinhart and Williamson were not directors until 2013.

(3)
Equity award for directors were approved in January 2013.

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Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

        The following table sets forth certain information regarding the beneficial ownership of our units as of April 9, 2013 by:

        All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders, as the case may be.

        Our General Partner is owned 100.0% by Southcross Energy LLC. Charlesbank Equity Fund VI, Limited Partnership and its affiliated investment funds hold 85.2% of the outstanding Class A Common Units, 93.5% of the outstanding Series A Preferred Units, 95.1% of the outstanding Redeemable Preferred Units and 73.8% of the outstanding Series B Redeemable Preferred Units of Southcross Energy LLC. In addition, members of management hold 10.6% of the outstanding Class A Common Units, 1.9% of the outstanding Series A Preferred Units, 0.3% of the outstanding Redeemable Preferred Units, 2.0% of the outstanding Series B Redeemable Preferred Units and 100% of the Special Class B Units of Southcross Energy LLC.

        The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a "beneficial owner" of a security if that person has or shares "voting power," which includes the power to vote or to direct the voting of such security, or "investment power," which includes the power to dispose of or to direct the disposition of such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units subject to options or warrants held by that person that are currently exercisable or exercisable within 60 days of April 9, 2013, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

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        The percentages of units beneficially owned are based on a total of 12,219,699 common units and 12,213,713 subordinated units outstanding as of April 9, 2013.

Name and address of beneficial owner
  Common units
beneficially owned 		  Percentage of
common units
beneficially owned 		  Subordinated units
beneficially owned 		  Percentage of
subordinated units
beneficially owned 		  Percentage of
total common and
subordinated units
beneficially owned 		 

Our General Partner:

                                

Southcross Energy LLC(1)(2)

     1,863,713     15.3 %   12,213,713     100.0 %   57.6 %

5% Owners Not Listed Above or Below:

                                

Charlesbank Equity Fund VI, Limited Partnership(2)(3)

     1,863,713     15.3 %   12,213,713     100.0 %   57.6 %

FMR LLC(4)

     1,587,780     13.0 %   —     —     6.5 %

Tortoise Capital Advisors, L.L.C.(5)

     1,036,692     8.5 %   —     —     4.2 %

Neuberger Berman Group LLC(6)

     1,563,435     12.8 %   —     —     6.4 %

Goldman Sachs Asset Management, L.P.(7)

     915,321     7.5 %   —     —     3.7 %

Directors and Named Executive Officers of Our General Partner:

                                

Samuel P. Bartlett(3)

     —     —     —     —     —  

Jon M. Biotti(3)

     —     —     —     —     —  

Kim G. Davis(3)

     —     —     —     —     —  

David W. Biegler(1)

     —     —     —     —     —  

Michael T. Hunter(1)

     —     —     —     —     —  

J. Michael Anderson(1)

     5,000     *     —     —     *  

Jerry W. Pinkerton(1)

     4,993     *     —     —     *  

Ronald G. Steinhart(1)(8)

     14,133     *     —     —     *  

Bruce A. Williamson(1)(9)

     2,993     *     —     —     *  

All current directors and executive officers of our General Partner as a group (consisting of 11 persons)(3)(10)

     18,940     *     —     —     *  
*
An asterisk indicates that the person or entity owns less than one percent.

(1)
The address for this person or entity is 1700 Pacific Avenue, Suite 2900, Dallas, Texas 75201.

(2)
Southcross Energy LLC owns 100% of our General Partner, 15.3% of our outstanding common units and 100% of our outstanding subordinated units. The following table sets forth the beneficial ownership of equity interests in Southcross Energy LLC as of April 9, 2013:

(3)
The Charlesbank Funds are members of Southcross Energy LLC and may therefore be deemed to beneficially own our common units and subordinated units held by Southcross Energy LLC. Samuel Bartlett, Jon Biotti and Kim Davis, each a director of our General Partner, are managing directors of Charlesbank Capital Partners, LLC, the investment adviser to the Charlesbank Funds. They disclaim beneficial interest in our common units and subordinated units except to the extent of their pecuniary interest therein. The address for this person or entity is 200 Clarendon Street, 54th Floor, Boston, Massachusetts 02116.

(4)
Based on a Schedule 13G filed by FMR LLC with the SEC on December 10, 2012. The filing was made jointly by FMR LLC and Edward C. Johnson 3d and sets forth an address for the filers at 82 Devonshire Street, Boston, Massachusetts 02109.

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(5)
Based on a Schedule 13G filed by Tortoise Capital Advisors, L.L.C. ("TCA") with the SEC on February 12, 2013. The filing reflects that TCA shares voting power over 980,031 common units and shares dispositive power over 1,036,692 common units. The filing provides an address for TCA at 11550 Ash Street, Suite 300, Leawood, Kansas 66211.

(6)
Based on a Schedule 13G filed by Neuberger Berman Group LLC ("Neuberger Group") with the SEC on February 14, 2013. The statement was made jointly by Neuberger Group and Neuberger Berman LLC and reflects that the filers share voting power over 1,208,507 common units and share dispositive power over 1,563,435 common units. The filing provides an address for the filers at 605 Third Avenue, New York, New York 10158.

(7)
Based on a Schedule 13G filed by Goldman Sachs Asset Management, L.P. ("GS Asset Management") with the SEC on February 14, 2013. The filing was made jointly by GS Asset Management and GS Investment Strategies, LLC and reflects that the filers share voting power and share dispositive power over 915,321 common units. The filing provides an address for the filers at 200 West Street, New York, New York 10282.

(8)
Includes 2,500 common units owned by each of two of Mr. Steinhart's sons and 1,000 common units owned by each of two trusts established for the benefit of Mr. Steinhart's grandchildren. Mr. Steinhart shares voting and dispositive power over such common units. Mr. Steinhart has no pecuniary interest in, and disclaims any ownership of, such common units.

(9)
Represents phantom units per the non-employee director deferred compensation plan. Mr. Williamson has the right to acquire these units within 30 days on termination of his services.

(10)
Does not include unvested phantom units granted to such persons under our long-term incentive plan, none of which will vest within 60 days of April 9, 2013.

Name of beneficial owner
  Class A
Common 		  Percentage of
Class A
Common
beneficially
owned 		  Class B
Special Units 		  Percentage of
Class B
Common
beneficially
owned 		  Series A
preferred 		  Percentage of
Series A
Preferred
beneficially
owned 		  Redeemable
Preferred
Units 		  Percentage of
Redeemable
Preferred
beneficially
owned 		  Series B
Redeemable
Preferred Units 		  Percentage of
Series B
Redeemable
Preferred Units
beneficially owned 		 

Charlesbank Equity Fund VI, Limited Partnership(a)

     1,118,717     85.2 %   —     —     11,075,303   93.5%     1,425,732     95.1 %   633,369     73.8 %

David W. Biegler(b)

     54,858     4.2 %   12,172     42.5 %   112,733   1.0%     —     —     11,051     1.3 %

Michael T. Hunter(b)

     49,858     3.8 %   12,172     42.5 %   63,233   *     —     —     6,528     0.8 %
*
Indicates the person or entity owns less than one percent.

(a)
Charlesbank Equity Fund VI, Limited Partnership and its affiliated investment funds (the "Charlesbank Funds") are members of Southcross Energy LLC and may therefore be deemed to beneficially own the common units and subordinated units held by Southcross Energy LLC. The address for the Charlesbank Funds is 200 Clarendon Street, 54th Floor, Boston, Massachusetts 02116.

(b)
The address for each individual is 1700 Pacific Avenue, Suite 2900, Dallas, Texas 75201.

Securities Authorized for Issuance Under Equity Compensation Plan(1)

        We have one compensation plan under which our common units are authorized for issuance, the LTIP. This equity compensation plan was approved by our unitholders. The following table sets forth certain information relating to the LTIP as of December 31, 2012:

 
   (a)
   (b)
   (c)
  
Plan category
  Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights 		  Weighted-average
exercise price of
outstanding options,
warrants and rights 		  Number of securities remaining
available for future issuance under
equity compensation plans
(excluding securities reflected
in column(a)) 		 

Equity compensation plans approved by securities holders

     144,500     —     1,605,500  

Equity compensation plans not approved by security holders

     —     n/a     n/a  
               

Total

     144,500   $ —     1,605,500  
               

   

(1)
See "Item 11—Executive Compensation—Long-Term Incentive Plan" for more information. No value is shown in column (b) of the table because the phantom units do not have an exercise price.

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Item 13.    Certain Relationships and Related Transactions, and Director Independence

        As of April 9, 2013, Southcross Energy LLC owns 1,863,713 common units and 12,213,713 subordinated units, representing a combined 56.5% limited partner interest in us. In addition, the Southcross Energy LLC owns and controls our General Partner, which owns a 2.0% General Partner interest in us and all of our incentive distribution rights.

        The following table summarizes the distributions and payments to be made by us to our General Partner and its affiliates in connection with our formation, ongoing operations and liquidation. These distributions and payments were determined before our IPO by and among affiliated entities and, consequently, are not the result of arm's-length negotiations.

 
    

Formation Stage

    

The consideration received by our General Partner and its affiliates for the contribution of the assets and liabilities to us
 
•    1,863,713 common units;

 
 
•    12,213,713 subordinated units;

 
 
•    all of our incentive distribution rights; and

 
 
•    2.0% general partner interest.

Operational Stage

    

Distributions of available cash to our General Partner and its affiliates
 
We generally make cash distributions of 98.0% to our unitholders pro rata, including Southcross Energy LLC, as the holder of an aggregate of 1,863,713 common units and 12,213,713 subordinated units, and 2.0% to our General Partner, assuming it makes any capital contributions necessary to maintain its 2.0% general partner interest in us. In addition, if distributions exceed the minimum quarterly distribution and target distribution levels, our General Partner is entitled to increasing percentages of the distributions, up to 48.0% of the distributions above the highest target distribution level in connection with its incentive distribution rights.

Payments to our General Partner and its affiliates
 
Our General Partner does not receive a management fee or other compensation for its management of us. However, our General Partner and its affiliates are entitled to reimbursement for all expenses incurred on our behalf, including, 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 the amount of these reimbursed expenses.

Withdrawal or removal of our General Partner
 
If our General Partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.

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Liquidation Stage

    

Liquidation
 
Upon our liquidation, our partners, including our General Partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Agreements with Southcross Energy LLC and Affiliates

        We and other parties entered into various documents and agreements with certain of our affiliates, as described in more detail below, in connection with our IPO in November 2012 and the acquisition of our assets from Southcross Energy LLC. These agreements address the acquisition of assets and the assumption of liabilities by us and our subsidiaries. These agreements were negotiated among affiliated parties and, consequently, were not the result of arm's-length negotiations.

Contribution, Conveyance and Assumption Agreement

        In connection with the closing of our IPO, we entered into a contribution, conveyance and assumption agreement effecting, among others, the following transactions:

Charlesbank and Management's Investments in Southcross Energy LLC

        From time to time since its inception, Southcross Energy LLC has issued membership interests in connection with capital contributions from its members, including Charlesbank and certain members of management. For the year ended December 31, 2009, Charlesbank contributed $111.8 million to Southcross Energy LLC and Messrs. Biegler, Hunter, Barcroft, Glasgow and Mueller contributed $1.3 million, $0.8 million, $0.2 million, $0.2 million and $0.1 million, respectively, to Southcross Energy LLC. In conjunction with such capital contribution, a member of management borrowed $150,000 from Southcross Energy LLC to fund his acquisition of equity interests pursuant to a promissory note. The balance of such note was paid in full subsequent to December 31, 2011.

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        There were no capital contributions for the year ended December 31, 2010. For the year ended December 31, 2011, Charlesbank contributed $14.3 million to Southcross Energy LLC in exchange for redeemable preferred units. During the same period, Messrs. Glasgow and Mueller contributed approximately $28,000 and $18,500, respectively, to Southcross Energy LLC in exchange for redeemable preferred units. For the year ended December 31, 2012, Charlesbank and certain other institutional investors contributed a total of $72.8 million to Southcross Energy LLC in exchange for Series B and C redeemable preferred units and Messrs Biegler and Hunter contributed approximately $954,000 and $325,000 for Series B and C redeemable preferred units. In connection with the IPO, and the over-allotment option, Southcross Energy LLC used $71.2 million to redeem all of the Series C redeemable preferred units and approximately 80% of the Series B redeemable preferred units.

Wells Fargo Bank, N.A.

        The Partnership entered into the credit agreements with syndicates of financial institutions and other lenders. These syndicates included affiliates of Wells Fargo Bank, N.A., an affiliate of which is a member of the investor group (See Note 15). Affiliates of Wells Fargo Bank, N.A. have from time to time engaged in commercial banking and financial advisory transactions with the Company in the normal course of business. Total fees paid, excluding interest, to affiliates of Wells Fargo, N.A., and its affiliates were $5.9 million, $1.0 million and $0.4 million for 2012, 2011 and 2010, respectively.

Private Placement of Series A Convertible Preferred Units

        On April 12, 2013, we entered into a Series A Convertible Preferred Unit Purchase Agreement (the "Purchase Agreement") with Southcross Energy LLC, an entity owned by Charlesbank Capital Partners, LLC, its affiliated investment funds and certain members of our management team and that owns and controls our general partner and an approximate 56.5% interest in us, pursuant to which we issued and sold 1,466,325 Series A Convertible Preferred Units (the "Series A Preferred Units") to Southcross Energy LLC for a cash purchase price of $22.86 per Series A Preferred Unit in a privately negotiated transaction (the "Private Placement"). For additional information with respect to the Private Placement, please read "Part II, Item 9B. Other Information—Item 1.01 Entry Into a Material Definitive Agreement.—Private Placement of Series A Convertible Preferred Units."

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

        The board of directors of our General Partner adopted the Code of Business Conduct and Ethics in connection with the closing of our initial public offering, which provides that the board of directors of our General Partner or its Conflicts Committee will periodically review all related-person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our General Partner or the Conflicts Committee considers ratification of a related-person transaction and determines not to so ratify, the Code of Business Conduct and Ethics provides that our management will make all reasonable efforts to cancel or annul the transaction.

        The Code of Business Conduct and Ethics provides that, in determining whether to recommend the initial approval or ratification of a related-person transaction, the board of directors of our General Partner or the Conflicts Committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction, (ii) the benefits that accrue to us as a result of the transaction, (iii) the terms available to unrelated third parties entering into similar transactions, (iv) the impact of the transaction on director independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediately family member of a director is a partner, shareholder, member or executive officer), (v) the availability of other sources for comparable products or services, (vi) whether it is a single transaction or a series of ongoing, related

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transactions, and (vii) whether entering into the transaction would be consistent with the Code of Business Conduct and Ethics.

Item 14.    Principal Accountant Fees and Services

        We have engaged Deloitte & Touche LLP as our independent registered public accounting firm. The following table summarizes fees we have paid Deloitte & Touche LLP for the audit of our annual financial statements and other services rendered for the years ended December 31, 2012 and 2011:

 
   Year ended
December 31, 		 
 
   2012   2011  

Audit fees

   $ 877,000   $ 745,000  

Audit-related fees

     —     —  

Tax fees

     33,804     87,147  

All other fees

     —     17,698  
           

  $ 910,804   $ 849,845  
           

Audit Committee Approval of Audit and Non-Audit Services

        The Audit Committee of the board of directors of our General Partner has adopted a policy with respect to services which may be performed by Deloitte & Touche LLP. This policy lists specific audit-related and tax services as well as any other services that Deloitte & Touche LLP is authorized to perform and sets out specific dollar limits for each specific service, which may not be exceeded without additional Audit Committee authorization. The Audit Committee receives quarterly reports on the status of expenditures pursuant to that policy. The Audit Committee reviews the policy at least annually in order to approve services and limits for the current year. Any service that is not clearly enumerated in the policy must receive specific pre-approval by the Audit Committee or by its chairman, to whom such authority has been conditionally delegated, prior to engagement.

        The Audit Committee has approved the appointment of Deloitte & Touche LLP as independent registered public accounting firm to conduct the audit of the Partnership's financial statements for the year ended December 31, 2012.

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PART IV

        

Item 15.    Exhibits and Financial Schedules

        (a)   Financial Statements

Report of Independent Registered Public Accounting Firm

   85

Consolidated Balance Sheets as of December 31, 2012 and 2011

   86

Consolidated Statements of Operations for the Years Ended December 31, 2012, 2011 and 2010

   87

Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2012, 2011 and 2010

   88

Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010

   89

Consolidated Statements of Changes in Partners' Capital and Members' Equity for the Years Ended December 31, 2012, 2011 and 2010

   90

Notes to Consolidated Financial Statements

   91

        An "Exhibit Index" has been filed as part of this report beginning in sub-item (b) below of this item and is incorporated herein by reference.

        Schedules other than those listed above are omitted because they are not required, not material, not applicable or the required information is shown in the financial statements or notes thereto.

        Agreements attached or incorporated herein as exhibits to this report are included to provide investors with information regarding the terms and conditions of such agreements and are not intended to provide any other factual or disclosure information about Southcross Energy Partners, L.P. or the other parties to the agreements.

        Such agreements may contain representations and warranties by the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and (i) should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate, (ii) have been qualified by disclosures that were made to the other party or parties in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement, (iii) may apply standards of materiality in a way that is different from what may be viewed as material to you or other investors and (iv) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments. Accordingly, the representations and warranties in such agreements may not describe the actual state of affairs as of the date they were made or at any other time.

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        (b)   Exhibits and Exhibit Index

  Exhibit
Number 		  Description
  3.1   Certificate of Limited Partnership of Southcross Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).
  3.2   First Amended and Restated Agreement of Limited Partnership of Southcross Energy Partners, L.P., dated as of November 7, 2012 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K dated November 7, 2012).
  3.3*   Second Amended and Restated Agreement of Limited Partnership of Southcross Energy Partners, L.P., dated as of April 12, 2013.
  3.4   Certificate of Formation of Southcross Energy Partners GP, LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).
  3.5   Amended and Restated Limited Liability Company Agreement of Southcross Energy Partners GP, LLC, dated as of November 7, 2012 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K dated November 7, 2012).
  4.1*   Registration Rights Agreement, dated as of April 12, 2013, by and between Southcross Energy Partners, L.P. and Southcross Energy LLC.
  10.1   Contribution, Conveyance and Assumption Agreement, dated as of November 7, 2012, by and among Southcross Energy Partners GP, LLC, Southcross Energy Partners, L.P., Southcross Energy Operating,  LLC and Southcross Energy LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated November 7, 2012).
  10.2   Second Amended and Restated Credit Agreement, dated as of November 7, 2012, among Southcross Energy Partners, L.P. as borrower, Wells Fargo Bank, N.A., as Administrative Agent, Citibank, N.A. and SunTrust Bank, as Co-Syndication Agents, Barclays Bank PLC, JPMorgan Chase Bank, N.A. and Compass Bank, as Co-Documentation Agents and the Lenders party thereto (filed as Exhibit 10.2 to the Current Report on Form 8-K dated November 7, 2012).
  10.3   Letter Agreement, dated as of December 31, 2012, by and among Southcross Energy Partners, L.P., Wells Fargo Bank, N.A., and certain other parties thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated December 31, 2012).
  10.4   First Amendment to Second Amended and Restated Credit Agreement, dated as of March 27, 2013, by and among Southcross Energy Partners, L.P., Wells Fargo Bank, N.A., as Administrative Agent, and each of the Lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated March 28, 2013).
  10.5*   Limited Waiver and Second Amendment to Second Amended and Restated Credit Agreement, dated as of April 12, 2013, by and among Southcross Energy Partners, L.P., Wells Fargo Bank, N.A., as Administrative Agent, and each of the Lenders party thereto.
  10.6#   Southcross Energy Partners, L.P. 2012 Long-Term Incentive Plan (filed as Exhibit 10.3 to the Current Report on Form 8-K dated November 7, 2012).
  10.7#   Form of Phantom Unit Award Agreement (incorporated by reference to Exhibit 10.5 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).

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  Exhibit
Number 		  Description
  10.8#   Severance Agreement, dated August 6, 2009, by and between Southcross Energy LLC and David W. Biegler (incorporated by reference to Exhibit 10.6 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).
  10.9#   Severance Agreement, dated August 6, 2009, by and between Southcross Energy LLC and Michael T. Hunter (incorporated by reference to Exhibit 10.7 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).
  10.10#   Severance Agreement, dated August 6, 2009, by and between Southcross Energy LLC and Ronald J. Barcroft (incorporated by reference to Exhibit 10.8 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).
  10.11#   Severance Agreement, dated April 2, 2012, by and between Southcross Energy LLC and J. Michael Anderson (incorporated by reference to Exhibit 10.9 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).
  10.12#   Southcross Energy Partners GP, LLC Non-Employee Director Compensation Arrangement.
  10.13#   Southcross Energy Partners, L.P. Non-Employee Director Deferred Compensation Plan.
  10.14*   Series A Preferred Unit Purchase Agreement, dated as of April 12, 2013, by and between Southcross Energy Partners, L.P. and Southcross Energy LLC.
  21.1*   List of Subsidiaries of Southcross Energy Partners, L.P.
  23.1*   Consent of Deloitte & Touche LLP.
  31.1*   Certification of Chief Executive Officer required by Rule 13a-14(a)/15d-14(a).
  31.2*   Certification of Chief Financial Officer required by Rule 13a-14(a)/15d-14(a).
  32.1*   Certifications of Chief Executive Officer and Chief Financial Officer required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
  101.INS*†   XBRL Instance Document
  101.SCH*†   XBRL Taxonomy Extension Schema
  101.CAL*†   XBRL Taxonomy Extension Calculation Linkbase
  101.DEF*†   XBRL Taxonomy Extension Definition Linkbase
  101.LAB*†   XBRL Taxonomy Extension Label Linkbase
  101.PRE*†   XBRL Extension Presentation Linkbase

        (c)   Financial Statement Schedules

161

Table of Contents


SIGNATURES

        Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

    Southcross Energy Partners, L.P.
    By: Southcross Energy Partners GP, LLC, our General Partner

 
 
By:
 
/s/ DAVID W. BIEGLER
 David W. Biegler
President and Chief Executive Officer
Dated: April 15, 2013        

        Pursuant to the requirements of the Securities Exchange Act of 1934, the following persons on behalf of the registrant and in the capacities and on the dates indicated have signed this report below.

SIGNATURE
 
TITLE
 
DATE

 
 
 
 
 
/s/ DAVID W. BIEGLER
 David W. Biegler		   Chairman of the Board, President, and Chief Executive Officer
 (Principal Executive Officer)		   April 15, 2013

/s/ J. MICHAEL ANDERSON
 J. Michael Anderson
 
Senior Vice President and Chief Financial Officer
 (Principal Financial Officer)
 
April 15, 2013

/s/ DAVID M. MUELLER
 David M. Mueller
 
Senior Vice President and Chief Accounting Officer
 (Principal Accounting Officer)
 
April 15, 2013

/s/ SAMUEL P. BARTLETT
 Samuel P. Bartlett
 
Director
 
April 15, 2013

/s/ JON M. BIOTTI
 Jon M. Biotti
 
Director
 
April 15, 2013

/s/ KIM G. DAVIS
 Kim G. Davis
 
Director
 
April 15, 2013

/s/ JERRY W. PINKERTON
 Jerry W. Pinkerton
 
Director
 
April 15, 2013

/s/ RONALD G. STEINHART
 Ronald G. Steinhart
 
Director
 
April 15, 2013

/s/ BRUCE A. WILLIAMSON
 Bruce A. Williamson
 
Director
 
April 15, 2013

162