10-K 1 sxe-12312013x10k.htm 10-K SXE-12.31.2013-10K

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
____________________________________________________________________________
FORM 10-K
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2013
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 x
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 x
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 x    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 x    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 x
 
Non-accelerated filer o
 (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 x
The aggregate market value of common units held by non-affiliates of the registrant on June 30, 2013 was approximately $229,045,500 based on the closing sale price and the number of outstanding common units on such date as reported on the New York Stock Exchange.

As of February 28, 2014, the registrant has 21,454,119 common units, 12,213,713 subordinated units and 1,800,886 Series A convertible preferred units outstanding. The registrant's common units trade on the New York Stock Exchange under the symbol "SXE".
DOCUMENTS INCORPORATED BY REFERENCE
None
 



Explanatory Note

As generally used in the energy industry and in this Form 10-K, the following terms have the following meanings:
/d: Per day
/gal: Per gallon
Bbls: Barrels
Condensate: Hydrocarbons that are produced from natural gas reservoirs but remain liquid at normal temperature and pressure
Lean gas: Natural gas that is low in NGL content
MMBtu: One million British thermal units
Mcf: One thousand cubic feet
Mgal: One thousand gallons
MMcf: One million cubic feet
NGLs: Natural gas liquids, which consist primarily of ethane, propane, isobutane, normal butane, natural gasoline and stabilized condensate
Residue gas: The pipeline quality natural gas remaining after natural gas is processed and NGLs and other matters are removed
Rich gas: Natural gas that is high in NGL content
Throughput: The volume of natural gas or NGLs transported or passing through a pipeline, plant, terminal or other facility
y-grade: Commingled mix of NGL components extracted via natural gas processing normally consisting of ethane, propane, isobutane, butane and natural gasoline


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INDEX TO ANNUAL REPORT ON FORM 10-K
For the Year Ended December 31, 2013
 

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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:
the volatility of natural gas, crude oil, and NGL prices and for the price and demand of products derived from these commodities;
competitive conditions in our industry and the extent and success of producers increasing production or replacing declining production and our success in obtaining new sources of supply;
industry conditions and supply of pipelines, processing and fractionation capacity relative to available natural gas from producers;
our dependence upon a relatively limited number of customers for a significant portion of our revenues;
actions or inactions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters and customers;
our ability to effectively recover NGLs at a rate equal to or greater than our contracted rates with customers;
our ability to produce and market NGLs at the anticipated differential to NGL index pricing;
our access to markets enabling us to match pricing indices for purchases and sales of natural gas and NGLs;
our ability to complete projects within budget and on schedule, including but not limited to, timely receipt of necessary government approvals and permits, our ability to control the costs of construction and other factors that may impact projects;
our ability to consummate acquisitions, successfully integrate the acquired businesses and realize anticipated cost savings and other synergies from any acquisitions;
our ability to manage over time changing exposure to commodity price risk;
the effectiveness of our hedging activities or our decisions not to undertake hedging activities;
our access to financing and ability to remain in compliance with our financing covenants;
our ability to generate sufficient operating cash flow to fund our quarterly distribution;
changes in general economic conditions;
the effects of downtime associated with our assets or the assets of third parties interconnected with our systems;
operating hazards, fires, natural disasters, weather-related delays, casualty losses and other matters beyond our control;
the failure of our processing and fractionation plants to perform as expected, including outages for unscheduled maintenance or repair;
the effects of laws and governmental regulations and policies;
the effects of existing and future litigation; and
other financial, operational and legal risks and uncertainties detailed from time to time in our filings with the U.S. Securities and Exchange Commission.
Developments in any of these areas could cause actual results to differ materially from those anticipated or projected, affect our ability to maintain distribution levels and/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 Part II, Item 7 of this report.
General Overview
Southcross Energy Partners, L.P. (the "Partnership," "Southcross," "we," "our" or "us") 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, when used for periods prior to our initial public offering ("IPO") on November 7, 2012, refer to Southcross Energy LLC and its consolidated subsidiaries, unless otherwise specifically noted. References in this Form 10-K to the Partnership, when used for periods beginning at or following our IPO, refer collectively to the Partnership and its consolidated subsidiaries. Southcross Energy LLC and its subsidiaries are controlled through investment funds and entities associated with Charlesbank Capital Partners, LLC ("Charlesbank"). Southcross Energy LLC holds all of the equity interests in Southcross Energy Partners GP, LLC, a Delaware limited liability company and our general partner (“General Partner”).
We are a master limited partnership that provides natural gas gathering, processing, treating, compression and transportation services and NGL fractionation and transportation services. We also source, purchase, transport and sell natural gas and NGLs. Our assets are located in South Texas, Mississippi and Alabama and include three gas processing plants, two fractionation plants and approximately 2,740 miles of pipeline. Our South Texas assets are located in or near the Eagle Ford shale region. We are headquartered in Dallas, Texas.
Recent Developments
Shelf Registration Statement
On November 29, 2013, we filed a Registration Statement on Form S-3 with the U.S. Securities and Exchange Commission (the "SEC") using a "shelf" registration process. Under the shelf registration process, we may over time, in one or more offerings, offer and sell any combination of the securities described in the prospectus, and the selling unitholders may, over time, in one or more offerings, offer and sell common units representing limited partner interests in us. We, together with Southcross Energy Finance Corp., may offer and sell debt securities described in the prospectus. Southcross Energy Finance Corp. may act as co-issuer of the debt securities, and certain direct or indirect subsidiaries of us may guarantee any debt securities offered, if and to the extent identified in the related prospectus supplement. The aggregate initial offering price of all securities sold by us under the prospectus will not exceed $675.0 million.
Public Offering
In February 2014, we completed a public equity offering of 9,200,000 additional common units and we received a capital contribution from our General Partner to maintain its 2.0% interest in us. The net proceeds from the public offering were $148.5 million. We plan to use the net proceeds from the offering to fund the recently announced construction of our new pipeline extending into Webb County, Texas and for general partnership purposes, including future permitted acquisitions. Pending such use, we temporarily repaid borrowings under our senior secured revolving credit facility with Wells Fargo, N.A. and a syndicate of lenders (as amended, our "Credit Facility"), which we will redraw to fund the construction of the new pipeline and for other general purposes.
Amendments to our Credit Facility
In connection with the commencement of our February 2014 public offering, we entered into a third amendment to our Credit Facility (the “Third Amendment”) that permits the construction of our pipeline into Webb County, Texas. The Third Amendment also permits us to acquire a specified target entity or its assets.
Emerging Growth Company Status
We are an "emerging growth company," as defined in the Jumpstart Our Business Startups Act of 2012 (the "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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an exemption from the auditor attestation requirement in the assessment of the emerging growth company's internal controls over financial reporting;
an exemption from the adoption of new or revised financial accounting standards until they would apply to private companies;
an exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor's report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; and
reduced disclosure about the emerging growth company's executive compensation arrangements pursuant to the rules applicable to smaller reporting companies.
We may take advantage of these provisions until we are no longer an emerging growth company, which will occur on the earliest of:
i.
the last day of the fiscal year following the fifth anniversary of our IPO;
ii.
the last day of the fiscal year in which we have more than $1.0 billion in annual revenues;
iii.
the date on which we have more than $700 million in market value of our common units held by non-affiliates; or
iv.
the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period.
We have elected to adopt the reduced disclosure requirements described above, except 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.
Ownership Structure
The following table depicts our ownership structure as of December 31, 2013:
Description
Percentage
ownership
Ownership by non-affiliates:
 
Public common units
38.8
%
Series A convertible preferred units
5.8
%
Southcross Energy LLC's ownership:

Common units
7.0
%
Subordinated units
45.6
%
Series A convertible preferred units
0.8
%
General partner interest
2.0
%
Total
100.0
%
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:
Capitalize on organic growth opportunities, with a focus on high-growth regions such as the Eagle Ford shale area. We intend to continue to evaluate and execute midstream projects involving the gathering, processing, treating, compression and transportation of natural gas and the transportation and fractionation of NGLs that enhance our existing systems as well as to aggregate supply and obtain access to premium markets for that supply. We plan to continue to focus on projects that we expect to increase our total throughput volume and generate attractive returns.
Continue to enhance the profitability of our existing assets.  We intend to increase the profitability of our existing asset base by identifying new business opportunities and adding new volumes of natural gas supplies to our existing assets. Specifically, we plan to capture incremental processing and NGL fractionation margins from our existing throughput and to undertake additional initiatives to increase gas volumes and enhance utilization of our assets, as well as to continue to enhance cost efficiencies.

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Pursue accretive acquisitions of complementary assets.  We intend to pursue accretive acquisitions that strategically expand or complement our existing asset portfolio. We monitor the marketplace to identify and pursue such acquisitions, with a particular focus on regions with potential for additional near-term development. To identify potential acquisitions of businesses or assets, we seek to utilize our industry knowledge, network of customers and strategic asset base. We intend to pursue acquisition opportunities both independently and jointly with our sponsor Charlesbank.
Manage our exposure to commodity price risk.  Because natural gas and NGL prices are volatile, we strive to mitigate the impact of fluctuations in commodity prices and to generate more stable cash flows. We have, and will continue to pursue, a contract portfolio that is heavily weighted towards fixed-fee and fixed-spread contracts, which are not directly sensitive to commodity price levels, while minimizing our direct exposure to commodity price fluctuations through hedging transactions when appropriate. We also will consider other methods of limiting commodity exposure, including the use of derivative instruments, as appropriate.
Maintain sound financial practices to ensure our long-term viability.  We intend to maintain our commitment to financial discipline, which we believe will serve the long-term interests of our unitholders. Consistent with such approach, we generally intend to fund the long-term capital requirements for expansion projects and acquisitions through a prudent combination of equity and debt capital.
Competitive Strengths
We believe that we are well-positioned to execute our business strategies successfully by capitalizing on the following competitive strengths:
Strategically located asset base.  The majority of our assets are located in, or within close proximity to, the Eagle Ford shale area in South Texas, which is one of the most active drilling regions in the U.S. We also operate in Mississippi and Alabama. Our geographic diversity reduces our reliance on any particular region, basin or gathering system. We believe the high growth potential of our South Texas assets coupled with the established, long-lived nature of our Mississippi and Alabama assets provide us with the opportunity to generate growth over the next several years. In addition, all of our assets have access to major natural gas market areas.
South Texas.  The close proximity of our South Texas system to the Eagle Ford shale area has allowed us to execute several recent organic capital projects in the area and to identify additional infrastructure needs adjacent to our existing systems. Our growth opportunities are impacted primarily by activity levels in our Eagle Ford Southcross pipeline catchment area. Our Eagle Ford Southcross pipeline catchment area includes multiple prospective production zones, including the Olmos tight sands formation, which overlays the Eagle Ford shale in areas connected by our pipeline systems. Our current activity provides us with a relationship with producers in the Eagle Ford shale region and an understanding of their future development plans and infrastructure needs. In addition, our South Texas systems benefit from access to the large industrial market in and around the Corpus Christi ship channel area.
Mississippi and Alabama.  We believe we are a leading service provider in the Mississippi and Alabama regions in which we operate. Our assets provide critical supply to our industrial, commercial and power generation customers and the wholesale markets via intrastate and interstate pipeline interconnects. Several of the large, gas-fired power plants across the southern portion of Mississippi access their primary source of natural gas through our system.
Reliable cash flows underpinned by long-term, fixed-fee and fixed-spread contracts.  We provide our services primarily under fixed-fee and fixed-spread contracts, which help to promote cash flow reliability and minimize our direct exposure to commodity price fluctuations.
Integrated midstream value chain.  We provide a comprehensive package of services to natural gas producers and customers including natural gas gathering, processing, treating, compression and transportation and NGL fractionation and transportation. We believe our ability to move natural gas and NGLs from the wellhead to market provides us with several advantages in competing for new supplies of natural gas. Specifically, the integrated nature of our business allows us to provide multiple services related to a single supply of natural gas and take advantage of incremental opportunities that present themselves along the value chain. We believe that this ability provides us with the opportunity to compete favorably on price against other companies that do not provide a similar full suite of services. Providing multiple services to customers also gives us a better understanding of each customer's needs and the marketplace. In addition to the advantages with our producers and customers, our ability to source and transport natural gas to market also allows us to satisfy our commercial and industrial customers' demand for natural gas. We

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believe all of these factors provide a competitive advantage relative to companies which do not offer this range of midstream services.
Experienced and incentivized management and operating teams.  Our senior executives have worked in several energy companies. Our executive officers have extensive experience in building, acquiring and managing midstream and other energy assets and are focused on optimizing our existing business and expanding our operations through disciplined development and accretive acquisitions. Many of our field operating managers and supervisors have long-standing experience operating our assets.
Supportive sponsor with significant industry expertise.  Charlesbank, the principal owner of our General Partner, has substantial experience as a private equity investor in the energy and midstream sectors. Charlesbank's investment professionals have deep experience in identifying, evaluating, negotiating and financing acquisitions and investments in the midstream sector. We believe that Charlesbank provides us with strategic guidance, financial expertise and potential capital support that enhance our ability to grow our asset base and cash flow.
Our Assets and Operations
Our assets consist of gathering systems, intrastate pipelines, three natural gas processing plants, two NGL fractionators, and ancillary assets and our operations are managed as and presented in one reportable segment.
The following tables provide information regarding our assets as of and for the year ended December 31, 2013:
 
As of December 31, 2013
 
Year Ended December 31, 2013
Gathering systems and intrastate pipelines
Miles
 
Approximate design of throughput capacity (Mcf/d)
 
Average throughput volumes of natural gas (MMBtu/d)
South Texas
1,595

 
590,000

 
375,777

Mississippi/Alabama
1,145

 
720,000

 
199,463

Total
2,740

 
1,310,000

 
575,240

 
 
 
As of December 31, 2013
 
Year Ended December 31, 2013
Processing plants
 
 
Approximate design of gas processing capacity (Mcf/d)
 
Average volume of processed gas (MMBtu/d)
Gregory
 
 
135,000

 
56,297

Conroe
 
 
50,000

 
29,205

Woodsboro
 
 
200,000

 
155,323

Total
 
 
385,000

 
240,825

 
 
 
As of December 31, 2013
 
Year Ended December 31, 2013
Fractionation plants
 
 
Approximate design of fractionation capacity (Bbls/d)
 
Average volume of NGLs sold from output (Bbls/d)
Gregory
 
 
4,800

 
2,504

Bonnie View
 
 
22,500

 
8,558

Total
 
 
27,300

 
11,062

We derive revenue primarily from fixed-fee and fixed-spread arrangements. For the year ended December 31, 2013, our fixed-fee and fixed-spread arrangements accounted for approximately 76% of our gross operating margin. Our contracts vary in duration from one month to several 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 end use markets to increase the gas throughput volume on our gathering and pipeline systems and through our processing plants.
The NGL products we produce have a variety of applications, including as heating fuels, petrochemical feedstocks and refining blend stocks. Our NGL products and the demand for these products are affected as follows:

Ethane. Ethane is typically supplied as purity ethane or as part of an ethane-propane mix. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and

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other chemical products. Although ethane is typically extracted as part of the mixed NGL stream at gas processing plants, if natural gas prices increase significantly in relation to NGL product prices or if the demand for ethylene falls, it may be more profitable for natural gas processors to leave the ethane in the natural gas stream thereby reducing the volume of NGLs delivered for fractionation and marketing.

Propane. Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a heating, engine and industrial fuel, and in agricultural applications such as crop drying. Changes in demand for ethylene and propylene could adversely affect demand for propane. The demand for propane as a heating fuel is significantly affected by weather conditions. The volume of propane sold is at its highest during the six-month peak heating season of October through March. Demand for our propane may be reduced during periods of warmer-than-normal weather.

Normal Butane. Normal butane is used in the production of isobutane, as a refined product blending component, as a fuel gas and in the production of ethylene and propylene. Changes in the composition of refined products resulting from governmental regulation, changes in feedstocks, products and economics, demand for heating fuel and for ethylene and propylene could adversely affect demand for normal butane.

Isobutane. Isobutane is predominantly used in refineries to produce alkylates to enhance octane levels. Accordingly, any action that reduces demand for motor gasoline or demand for isobutane to produce alkylates for octane enhancement could reduce demand for isobutane.

Natural Gasoline. Natural gasoline is used as a blending component for certain refined products and as a feedstock used in the production of ethylene and propylene. Changes in the mandated composition resulting from governmental regulation of motor gasoline and in demand for ethylene and propylene could adversely affect demand for natural gasoline.

NGLs and products produced from NGLs also compete with global markets. Any reduced demand for ethane, propane, normal butane, isobutane or natural gasoline in the markets we access for any of the reasons stated above could adversely affect demand for the services we provide as well as NGL prices, which would negatively impact our results of operations and financial condition.
South Texas
The assets in our South Texas region are located between Conroe and Freer, a city that is located approximately 50 miles west of Corpus Christi, Texas. As of December 31, 2013, these assets consisted of approximately 1,595 miles of pipeline ranging in diameter from 2 to 20 inches, our Woodsboro processing plant, our Bonnie View NGL fractionation facility, our Gregory processing plant and NGL fractionation facility, 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 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.

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Our Woodsboro processing plant is a 200 MMcf/d cryogenic processing plant located in Refugio County, Texas. Our Bonnie View NGL fractionation plant, also in Refugio County, Texas has a capacity of 22,500 Bbls/d.
In February 2013, we completed construction and commenced full flow-through of our 20-inch Bee Line pipeline to move rich gas to our Woodsboro processing plant. The Bee Line is a 57-mile pipeline with capacity of approximately 320 MMcf/d. In July 2013, we commenced flow-through of our new 16-inch, 9.4-mile pipeline from our Karnes County pipeline into Bee County. In October 2013, we initiated operation of a new 12-inch, 3.3-mile pipeline lateral off of our McMullen pipeline to move rich gas to our Woodsboro processing plant.
Prior to startup of our Woodsboro processing plant, the majority of our rich 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 was in effect through May 31, 2013. The volumes of our gas covered by the agreement gradually decreased between January 2013 and the agreement's termination date, after which all of our rich gas was routed to our Woodsboro processing plant, our Gregory processing plant and, if necessary, to other third-party processing plants.
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.

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Purity ethane produced from our Gregory and Bonnie View facilities is shipped via pipeline to a subsidiary of The Dow Chemical Company. During 2013, Trafigura AG began purchasing and trucking our NGLs produced from our Bonnie View and Gregory facilities.
On January 26, 2013, as the turnaround maintenance at our Gregory processing and NGL fractionation plants was nearing completion, 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 recovered $1.0 million in 2013 for this loss under our insurance policies and believe it is probable that we will recover the remaining costs from our insurers, less our $0.3 million deductible. We have also filed an insurance claim under our business interruption insurance policy as a result of the business interruption we experienced in connection with the fire at the Gregory facility. As of December 31, 2013, our business interruption claim is under review and the amount of proceeds to be received therefrom has not been determined. While there was financial impact in the first quarter of 2013 due to reduced operations at our Gregory facility, there has been no lasting operational or financial impact from the fire.
Our Conroe processing plant and gathering system is a 50 MMcf/d cryogenic natural gas plant. The 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. 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 Gas Company (SONAT) and Texas Eastern—to supplement supply on the system or to market gas off the system.

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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.

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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 DCP Midstream LLC, Energy Transfer Partners, L.P., Enterprise Products Partners LP, Boardwalk Pipeline Partners, LP, Kinder Morgan Energy Partners LP, Southeast Supply Header, LLC and Atlas Pipeline, LP.
In addition to competing for natural gas supply volumes, we face competition for customer markets in selling residue gas and NGLs. Competition is based primarily on the proximity of pipelines to the markets, price and assurance of supply.
Customers and Concentration of Credit Risk
Our 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. We analyze customers' historical financial and operational information prior to extending credit and we monitor creditworthiness on a periodic basis.
Our top ten customers accounted for 59.7% of our revenue for the year ended December 31, 2013, including one customer, Sherwin Alumina Company, which accounted for 11.7% of our 2013 revenue.

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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 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. 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.
PHMSA issued a rule that increased the maximum administrative civil penalties for violation of the pipeline safety laws and regulations after January 3, 2012 to $200,000 per violation per day, with a maximum of $2,000,000 for a series of violations. The PHMSA issued a final rule applying safety regulations to certain rural, low-stress, hazardous liquid pipelines that were not covered previously by some of its safety regulations and has also published advanced notice of proposed rulemakings to solicit comments on the need for changes to its natural gas and liquid pipeline safety regulations, including gathering lines. The PHMSA recently published an advisory bulletin providing guidance on verification of records related to pipeline maximum allowable operating pressure. We have performed hydrotests of our facilities to establish the maximum allowable operating pressure and do not expect that any final rulemaking by PHMSA regarding verification of maximum allowable operating pressure would materially affect our operations or revenue. We believe our records relating to allowable maximum operating pressure to be reliable, traceable, verifiable and complete. 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 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 Emergency Planning and Community Right-to-Know Act (the “EPCRA”) 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:

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The Enviornmental Protection Agency's (the "EPA") Chemical Accident Prevention Provisions, also known as the Risk Management Plan requirements, which are designed to prevent the accidental release of toxic, reactive, flammable or explosive materials;
OSHA Process Safety Management Regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive materials; and
Department of Homeland Security Chemical Facility Anti-Terrorism Standards, which are designed to regulate the security of high-risk chemical facilities.
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 "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. Presently, we are awaiting FERC approval of rates for one of our subsidiaries which filed a petition in early February of 2014. Our next subsidiary to file a petition for the FERC’s rate approval will be in April 2015. 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 that 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

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increases FERC regulation of certain intrastate and Hinshaw pipelines. See "Government Regulation—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 gathering pipelines meet the traditional tests that the FERC has used to 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) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) 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 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. In addition, the Commodities Futures Trading Commission, or the CFTC, is directed under the Commodities Exchange Act, or CEA, to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Act and other authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory

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authority to seek civil penalties of up to the greater of one million dollars ($1,000,000) or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA.
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 FERC'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.
On November 15, 2012, the FERC issued a Notice of Inquiry seeking public comment on the issue of whether to amend its regulations under the natural gas market transparency provisions of Section 23 of the NGA, as adopted by EPAct 2005, to consider the extent to which quarterly reporting of every natural gas transaction within the FERC’s NGA jurisdiction that entails physical delivery for the next day or next month would provide useful information for improving natural gas market transparency. 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 Gulf Coast Transmission Ltd., are required to file gas tariffs and Southcross NGL Pipeline Ltd. has filed a NGL tariff with the RRC.
In Mississippi, the Mississippi Public Service Commission 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.

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

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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 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.
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,

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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 and our customers 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 January 30, 2013, the EPA finalized amendments to new regulations under the CAA to control emissions of hazardous air pollutants from stationary reciprocating internal combustion engines and stationary internal combustion engines. Subsequently, the EPA received three petitions for reconsideration of the final rules. On September 5, 2013, EPA agreed to reconsider the rules with respect to only the three issues raised in the petitions and requested public comment. We are currently evaluating the impact that the final rules will have on our operations. We are currently in full compliance with the rule as is and do not expect any amendments as a result of the three petitions to have any material effect. The scope of applicability for all of our engines is the requirement to follow a prescribed maintenance plan. We do not expect to be required to purchase, install, monitor or maintain additional emissions control equipment as a result of this rule.
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 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 established specific new requirements for emissions from compressors, controllers, dehydrators, storage tanks, gas processing plants and certain other equipment. On August 5, 2013, the EPA finalized updates to the 2012 performance standards for emissions of volatile organic compounds (“VOCs”) from storage tanks used in oil and natural gas production and transmission, which, among other things, adjusted reporting requirements and phased in the date by which storage tanks must install VOC controls. Compliance with these 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.

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Safe Drinking Water Act
The underground injection of oil and natural gas wastes is 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 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% 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, Woodsboro, Bonnie View and Conroe 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, and which has been repeatedly revised and amended with respect to such matters as technical corrections, business confidentiality and deadlines for compliance, requires annual reporting of greenhouse gas emissions by regulated facilities to the EPA. We have submitted the reports required under this rule on a timely basis 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.

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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.
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
On January 1, 2013, all employees of the predecessor prior to our IPO 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 our General Partner employed 174 employees as of December 31, 2013.
Available Information, “Lead Director” 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 SEC under the Securities Exchange Act of 1934, as amended (the "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 website located at www.southcrossenergy.com.
The public may obtain such reports from the SEC's 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.
Interested parties may communicate directly with the independent directors of our General Partner by submitting a communication in an envelope marked “Confidential” addressed to the “Independent Members of the Board of Directors” in care of Jerry W. Pinkerton, or such other director designated as the “Lead Director” under the Corporate Governance Guidelines adopted by our General Partner and disclosed in any future public filings with the SEC, and delivering it to 1700 Pacific Avenue, Suite 2900, Dallas, Texas 75201.
Lead Director

In accordance with the Corporate Governance Guidelines adopted by our General Partner, Jerry W. Pinkerton is the “Lead Director” responsible for chairing the executive sessions required to be held by our General Partner’s non-management directors. The Corporate Governance Guidelines permit the Chairman of the board of directors of our General Partner to designate another independent director to lead such meetings as the “Lead Director.”
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 website at www.southcrossenergy.com. We also 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 (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 cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our General Partner, to enable us to pay the minimum quarterly distribution, or any distribution, to our unitholders.
We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
the volume of natural gas we gather, process, treat, compress and transport and the volume of NGLs we fractionate and transport;
the level of production of, and the demand for, oil, natural gas and NGLs and the market prices of oil, natural gas and NGLs;
damage to pipelines, facilities, plants, related equipment and surrounding properties caused by hurricanes, earthquakes, floods, fires, severe weather, explosions and other natural disasters and acts of terrorism including damage to third-party pipelines or facilities upon which we rely for transportation and processing services;
outages at the processing or NGL fractionation facilities owned by us or third parties caused by mechanical failure and maintenance, construction and other similar activities;
leaks or accidental releases of products or other materials into the environment, whether as a result of human error or otherwise;
prevailing economic and market conditions;
realized prices received for natural gas and NGLs;
fixed-fees associated with our services;
the market prices of natural gas and NGLs relative to one another, which affects our processing margins;
capacity charges and volumetric fees associated with our transportation services;
the level of competition from other midstream energy companies in our geographic markets;
the level of our operating, maintenance and general and administrative costs; and
regulatory action affecting the supply of, or demand for, natural gas, the maximum transportation rates we can charge on our pipelines, our existing contracts, our operating costs or our operating flexibility.
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 level of capital expenditures we make;
the cost of acquisitions, if any;
our debt service requirements and other liabilities;
fluctuations in our working capital needs;
our ability to borrow funds and access capital markets;
restrictions contained in our debt agreements;

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the amount of cash reserves established by our General Partner; and
other business risks affecting our cash levels.
Because of the natural decline in production from existing wells in our areas of operation, our success depends in part on producers growing production and replacing declining production and also on our ability to obtain new sources of natural gas. Any decrease in the volumes of natural gas that we gather, compress, process, treat or transport or in the volumes of NGLs that we fractionate or transport could adversely affect our business and operating results.
The natural gas volumes that support our business depend on the level of production from natural gas wells connected to our systems, which may be less than expected and will naturally decline over time. As a result, our cash flows associated with these wells 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:
the availability and cost of capital;
prevailing and projected oil, natural gas and NGL prices;
demand for oil, natural gas and NGLs;
levels of reserves;
geological considerations;
environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and
the availability of drilling rigs and other costs of production and equipment.
Fluctuations in energy prices can also greatly affect the development of oil and natural gas reserves. Drilling and production activity generally decreases as natural gas, 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.
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 natural gas and liquid reserves connected to our gathering and transportation systems on a regular or ongoing basis; therefore, in the future, volumes of natural gas on our systems could be less than we anticipate.
We do not 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.
Our success depends on drilling activity and our ability to attract and maintain customers in a limited number of geographic areas.
A significant portion of our assets is located in the Eagle Ford shale area, and we intend to focus our future capital expenditures largely on developing our business in this area. As a result, our financial condition, results of operations and cash flows are significantly dependent upon the demand for our services in this area. Due to our focus on this area, an adverse

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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.
Our failure to effectively execute our major development projects could result in delays and/or cost over-runs, limitations on our growth and negative effects on our operating results, liquidity and financial position.
We are engaged in the planning and construction of several major development projects, some of which will take a number of months before commercial operation. These projects are complex and subject to a number of factors beyond our control, including delays from third-party landowners, the permitting process, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Also, legislative or regulatory intervention may create limits or prohibit our ability to perform desired capital projects. Delays in the completion of these projects could have a material adverse effect on our business, financial condition, results of operations and liquidity. Estimating the timing and expenditures related to these development projects is complex and subject to variables that can increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and capital position could be adversely affected. This level of development activity requires effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls.
Natural gas and NGL prices are volatile, and a change in these prices in absolute terms, or an adverse change in the prices of natural gas and NGLs relative to one another, could adversely affect our gross operating margin and cash flow and our ability to make cash distributions to our unitholders.
We are subject to risks due to frequent and often substantial fluctuations in commodity prices. In the past, the prices of natural gas, NGLs and other commodities have been extremely volatile, and we expect this volatility to continue. Our future cash flow may be materially adversely affected if we experience significant, prolonged pricing deterioration.
The markets for and prices of natural gas, NGLs and other commodities depend on factors that are beyond our control. These factors include the supply of and demand for these commodities, which fluctuate with changes in market and economic conditions and other factors, including:
worldwide economic conditions;
worldwide political events, including actions taken by foreign oil and natural gas producing nations;
worldwide weather events and conditions, including natural disasters and seasonal changes;
the levels of domestic production and consumer demand;
the availability of transportation systems with adequate capacity;
the volatility and uncertainty of regional pricing differentials;
the price and availability of alternative fuels;
the effect of energy conservation measures;
the nature and extent of governmental regulation and taxation;
fluctuations in demand from electric power generators and industrial customers; and
the anticipated future prices of oil, natural gas, NGLs and other commodities.
Our exposure to direct commodity price risk and volatility in costs to market products may vary.
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.

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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.
Unexpected volume changes due to production variability or to gathering, plant or pipeline system disruptions may increase our exposure to commodity price movements.
We sell processed natural gas to third parties at plant tailgates, pipeline pooling points or at inlet meters to the sites of industrial and utility customers. These sales may be interrupted by disruptions to volumes anywhere along the system. We attempt to balance sales with volumes supplied, but unexpected volume variations due to production variability or to gathering, plant or pipeline system disruptions may expose us to volume imbalances which, in conjunction with movements in commodity prices, could materially impact our income from operations and cash flow.
We may not successfully balance our purchases and sales of natural gas, which would increase our exposure to commodity price risks.
We purchase from producers and other suppliers a substantial amount of the natural gas that flows through our pipelines and processing facilities for sale to third parties, including natural gas marketers and others.
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 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.
Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.
We compete with other similarly sized midstream companies in our areas of operation. Some of our competitors are large companies that have greater financial, managerial and other resources than we do. In addition, some of our competitors have assets in closer proximity to natural gas supplies and have available idle capacity in existing assets that would not require new capital investments for use. Our competitors may expand or construct gathering, compression, treating, processing or transportation systems or 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.
Our gathering, processing and transportation contracts subject us to contract renewal risks.
We gather, purchase, process, treat, compress, transport and sell most of the natural gas and NGLs on our systems under contracts with terms of various durations. As these contracts expire, we may have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. We may be unable to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. 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.

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We depend on a relatively limited number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, any one or more of these customers could adversely affect our ability to make cash distributions to our unitholders.
A significant percentage of our revenue is attributable to a relatively limited number of customers. Our top ten customers accounted for 59.7% of our revenue for the year ended December 31, 2013, including one customer that accounted for 11.7%. 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.
If third-party pipelines, other midstream facilities, or purchasers of our products interconnected to our gathering or transportation systems become partially or fully unavailable, or if the volumes we gather or transport do not meet the natural gas and NGL quality requirements of such pipelines or facilities, our gross operating margin and cash flow and our ability to make distributions to our unitholders could be adversely affected.
Our natural gas gathering and transportation pipelines, NGL pipelines and processing facilities connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of such third-party pipelines, processing plants, facilities of purchasers of our products and other midstream facilities is not within our control. These pipelines and 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 several decades and we have a limited ownership history with respect to all of our assets. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with our pipelines and processing and treating plants that could have a material adverse effect on our business and operating results.
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 of which our executive management team may be unaware and that may have a material adverse effect on our business and results of operations. The age and condition of our pipeline systems could also result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of our pipeline systems could adversely affect our business and results of operations and our ability to make cash distributions to our unitholders.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not adequately insured or if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, our operations and financial results could be adversely affected.
Our operations are subject to all of the risks and hazards inherent in the gathering, compressing, treating, processing and transportation of natural gas and the fractionation and transportation of NGLs, including:
damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters, acts of terrorism and actions by third parties;
inadvertent damage from construction, vehicles, farm and utility equipment;
leaks of natural gas and other hydrocarbons or losses of natural gas as a result of human error, the malfunction of equipment or facilities;

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ruptures, fires and explosions; and
other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. 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.
We intend to grow our business in part by seeking strategic acquisition opportunities. If we are unable to make acquisitions on economically acceptable terms from third parties, our future growth will be affected, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per unit basis.
Our ability to grow is affected, in part, 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 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. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.
Any acquisition involves potential risks, including, among other things:
mistaken assumptions about volumes, revenue and costs, including synergies;
an inability to secure adequate customer commitments to use the acquired systems or facilities;
the risk that natural gas reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;
an inability to integrate successfully the assets or businesses we acquire, particularly given the relatively small size of our management team and its limited history with our assets;
coordinating geographically disparate organizations, systems and facilities;
the assumption of unknown liabilities;
limitations on rights to indemnity from the seller;
mistaken assumptions about the overall costs of equity or debt;
the diversion of management's and employees' attention from other business concerns;
unforeseen difficulties operating in new geographic areas and business lines; and
customer or key employee losses at the acquired businesses.
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

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Our growth strategy requires access to new capital. Tightened capital markets or increased competition for investment opportunities could impair our ability to grow.
We continuously consider and enter into discussions regarding potential acquisitions or growth capital expenditures. Any limitations on our access to new capital will impair our ability to execute this strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire strategic and accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our initial cost of equity include market conditions, including our then current unit price, fees we pay to underwriters and other offering costs, which include amounts we pay for legal and accounting services. The primary factors influencing our cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges we pay to lenders.
Weak economic conditions and the volatility and disruption in the financial markets could increase the cost of raising money in the debt and equity capital markets substantially while diminishing the availability of funds from those markets. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers. These factors may impair our ability to execute our growth strategy.
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.
We may not have access to capital due to deterioration of conditions in the global capital markets, weakening of macroeconomic conditions and negative changes in financial performance.
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, including our financial performance, could cause us to incur increased borrowing costs and to have greater difficulty accessing public and private markets for both secured and unsecured debt. 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.
Because our common units are yield-oriented securities, increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
Interest rates may increase in the future. As a result, interest rates on our future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.
As of December 31, 2013, we had total indebtedness of $267.3 million. In February 2014, our indebtedness was reduced by $148.5 million as a result of our equity offering completed in February 2014. Our future level of debt could have important consequences to us, including the following:
our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
our funds available for operations, future business opportunities and cash distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;
we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
our flexibility in responding to changing business and economic conditions may be limited.
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which

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are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.
A shortage of skilled labor in the midstream natural gas industry could reduce labor productivity and increase costs, which could have a material adverse effect on our business and results of operations.
The gathering, 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.
Restrictions in our Credit Facility could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.
We 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:
incur or guarantee additional debt;
make distributions on or redeem or repurchase units;
make certain investments and acquisitions;
make capital expenditures;
incur certain liens or permit them to exist;
enter into certain types of transactions with affiliates;
merge or consolidate with another company; and
transfer, sell or otherwise dispose of assets.
Our 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 our 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, Note 7 of this report.
We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.
Our natural gas gathering, processing, 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:
the federal Clean Air Act and analogous state laws that impose obligations related to air emissions;
the federal Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or the Superfund law, and analogous state laws that regulate the cleanup of hazardous substances that may be or have been

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released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal;
the federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws that regulate discharges from our facilities into state and federal waters, including wetlands;
the federal Oil Pollution Act, also known as OPA, and analogous state laws that establish strict liability for releases of oil into waters of the U.S.;
the federal Resource Conservation and Recovery Act, also known as RCRA, and analogous state laws that impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities;
the Endangered Species Act, also known as the ESA; and
the Toxic Substances Control Act, also known as TSCA, and analogous state laws that impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.
These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations or at locations currently or previously owned or operated by us. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions or costly pollution control measures. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay 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.
Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the natural gas services we provide.
In recent years, the U.S. Congress has considered legislation to restrict or regulate emissions of greenhouse gases, or GHGs, such as carbon dioxide and methane that may be contributing to global warming. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues. In addition, almost half of the states, either individually or through multi‑state regional initiatives, have begun to address GHG emissions, primarily through the planned development of emission inventories or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. Depending on the scope of a particular program, we could be required to purchase and surrender allowances for GHG emissions resulting from our operations (e.g., at compressor stations). Although most of the state‑level initiatives have to date been focused on large sources of GHG emissions, such as electric power plants, it is possible that smaller sources such as our gas-fired compressors could become subject to GHG-related regulation. Depending on the particular program, we could be required to control emissions or to purchase and surrender allowances for GHG emissions resulting from our operations.

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Independent of Congress, the EPA has adopted 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 GHGs 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 GHG emissions from specified large GHG 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 GHG emissions by regulated facilities to the EPA by September 2012 for emissions during 2011 and annually 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 GHG emissions under the Clean Air Act. Several of the EPA’s GHG 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 GHG emissions would impact our business, any future federal or state laws or implementing regulations that may be adopted to address GHG emissions could require us to incur increased operating costs and could adversely affect demand for the natural gas we gather, 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 GHGs could include new or increased costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions and administer and manage a GHG emissions program. While we may be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities, such recovery of costs is uncertain. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for natural gas, resulting in a decrease in demand for our services. We cannot predict with any certainty at this time how these possibilities may affect our operations.
Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenues.
A portion of our customers' natural gas production is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. Hydraulic fracturing has become the subject of opposition, the subject of additional private and government studies and the subject of increased federal, state and local regulation. For example, 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. In addition, the EPA has announced plans to develop standards for discharges of hydraulic fracturing wastewaters by 2014, has adopted new regulations under the Clean Air Act requiring, among other things, the use of “reduced emission completion” technology for certain hydraulic fracturing operations and related equipment, and has announced plans to solicit public comment on a possible federal reporting requirement for fluids used in hydraulic fracturing pursuant to the Toxic Substances Control Act. Compliance with such laws and regulations 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.
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 and adversely affect our revenue and results of operations.
Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.

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One of the ways we intend to grow our business is through organic growth projects. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control. Such expansion projects may also require the expenditure of significant amounts of capital, and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, our revenue may not increase immediately upon the expenditure of funds on a particular project.
For instance, if we expand a pipeline, the construction may occur over an extended period of time, yet we will not receive any material increases in revenue until the project is completed and placed into service. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize or only materializes over a period materially longer than expected. Since we are not engaged in the exploration for and development of natural gas and oil reserves, we often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in that area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate as a result of the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.
In addition, the construction of additions to our existing gathering and transportation assets may require us to obtain new rights-of-way or environmental authorizations. We may be unable to obtain such rights-of-way or authorizations and may, therefore, be unable to connect new natural gas volumes to our systems or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or authorizations or to renew existing rights-of-way or authorizations. If the cost of renewing or obtaining new rights-of-way or authorizations increases materially, our cash flows could be adversely affected.
A change in the jurisdictional characterization or regulation of our assets or a change regulatory laws and regulations or the implementation of existing laws and regulations could result in increased regulation of our assets which could materially and adversely affect our financial condition, results of operations and cash flows.
Intrastate transportation facilities that do not provide interstate transmission services and gathering facilities (whether or not they provide interstate transportation services) are exempt from the jurisdiction of the 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 ("NGPA") this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.
Some of our intrastate pipelines provide interstate transportation service regulated under Section 311 of the Natural Gas Policy Act of 1978, or NGPA. Rates charged under NGPA Section 311 are limited to rates deemed by FERC to be "fair and equitable." Accordingly, such regulation may prevent us from recovering our full cost of service allocable to such interstate transportation service. In addition, some of our intrastate pipelines may be subject to complaint-based state regulation with respect to our rates and terms and conditions of service, which may prevent us from recovering some of our costs of providing service. The inability to recover our full costs due to FERC and state regulatory oversight and compliance could materially and adversely affect our revenues.
Moreover, FERC regulation affects our gathering, transportation and compression business generally. The FERC's policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, market transparency, market manipulation, ratemaking, capacity release, segmentation and market center promotion, directly and indirectly affect our gathering 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.

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State regulation of gathering facilities generally includes safety and environmental regulation and complaint-based ratable take requirements and rate regulation. State and local regulation may cause us to incur additional costs or limit our operations, may prevent us from choosing the customers to which we provide service. Due to increased gathering activity, among other considerations, natural gas gathering is beginning to receive greater legislative and regulatory scrutiny which could result in new regulations or enhanced enforcement of existing laws and regulations. Increased regulation of natural gas gathering could adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.
We may incur greater than anticipated costs and liabilities as a result of pipeline safety regulation, including integrity management program testing and related repairs.
The DOT, through its Pipeline and Hazardous Materials Safety Administration, has adopted regulations requiring pipeline operators to develop integrity management programs for transmission pipelines located where a leak or rupture could harm "high consequence areas" unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. High consequence areas include high population areas, areas that are sources of drinking water, ecological resource areas that are unusually sensitive to environmental damage from a pipeline release and commercially navigable waterways. The regulations require operators, including us, to:
perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
maintain processes for data collection, integration and analysis;
repair and remediate pipelines as necessary; and
implement preventive and mitigating actions.
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 $0.5 million during 2013 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 2013 testing program.
Should we fail to comply with DOT or comparable state regulations, we could be subject to penalties and fines. Additionally, pipeline safety reforms, including new requirements, enhanced penalties and changes in the administration and enforcement of safety laws have been implemented in recent years and the consideration of additional reforms is ongoing. Such legislative and regulatory changes could have a material effect on our operations and costs of transportation service.
The adoption and implementation of new statutory and regulatory requirements for swap transactions could increase the costs and have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.
In July 2010, federal legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, was enacted. The Dodd-Frank Act provides new statutory requirements for swap transactions, including oil and gas hedging transactions. These statutory requirements must be implemented through regulation, primarily through rules to be adopted by the Commodity Futures Trading Commission ("CFTC"). While certain regulations have been promulgated and are already in effect, the rulemaking and implementation process is still ongoing, and we cannot yet predict the ultimate effect of the rules and regulations on our business.
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 many 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 swaps will be subject to new reporting, and all market participants will be subject to new 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.
To date, however, several categories of swaps have been designated by the CFTC as mandatorily clearable swaps. These swaps will also be required to be traded on registered swap execution facilities or exchanges. Both the clearing and the trading

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requirements are likely to significantly increase transaction costs of entering into swaps (e.g., by entering into agreements with and paying commission to brokerage and clearing intermediaries). Even if we chose to rely on the end-user exception from the clearing and trading requirements, such swap will likely to be subject to the enhanced margin requirements because the CFTC has proposed, but has not yet finalized, rules requiring market participants to post margin in connection with uncleared swaps. Posting of such margin could impact liquidity and reduce our cash available for capital expenditures or other partnership purposes. A requirement to post cash collateral could therefore reduce our willingness or ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of swaps as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

The CFTC has also issued regulations to set position limits for certain futures and option contracts in the major energy, metals and agricultural markets as well as for swaps that are the economic equivalents of such futures transactions. The CFTC’s position limits rules were to become effective on October 12, 2012, but a United States District Court vacated and remanded the position limits rules to the CFTC. On November 5, 2013, the CFTC re-proposed a rulemaking on position limits and aggregation; however, it is uncertain at this time whether, when, and to what extent the CFTC’s position limits rules will become effective.

The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may increase our exposure to less creditworthy counterparties. We may also need to expend significant resources complying with and adapting to the new regulatory regime, including documentation, confirmation, and significant reporting and recordkeeping requirements.

Cyber-attacks, acts of terrorism or other disruptions could adversely impact our results of operations and our ability to make cash distributions to unitholders.
We are subject to cyber-security risks related to breaches in the systems and technology that we use (i) to manage our operations and other business processes and (ii) to protect sensitive information maintained in the normal course of our businesses. The gathering, processing and transportation of natural gas from our gathering, processing and pipeline facilities are dependent on communications among our facilities and with third-party systems that may be delivering natural gas into or receiving natural gas and other products from our facilities. Disruption of those communications, whether caused by physical disruption such as storms or other natural phenomena, by failure of equipment or technology, or by manmade events, such as cyber-attacks or acts of terrorism, may disrupt our ability to deliver natural gas and control these assets. Cyber-attacks could also result in the loss of confidential or proprietary data or security breaches of other information technology systems that could disrupt our operations and critical business functions, adversely affect our reputation, and subject us to possible legal claims and liability, any of which could have a material adverse effect on our results of operations and our ability to make cash distributions to unitholders. In addition, our natural gas pipeline systems may be targets of terrorist activities that could disrupt our ability to conduct our business and have a material adverse effect on our results of operations and our ability to make cash distributions to unitholders. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.
Our ability to operate our business effectively could be impaired if we fail to attract and retain key management and personnel.
Our ability to operate our business and implement our strategies will depend on our continued ability to attract and retain highly skilled management personnel with midstream natural gas industry experience. Competition for these persons in the midstream natural gas industry is intense. Given our size, we may be at a disadvantage, relative to our larger competitors, in the competition for these personnel. We may not be able to continue to employ our senior executives and key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract our senior executives and key personnel could have a material adverse effect on our ability to effectively operate our business.
We do not have employees. We rely solely on officers and employees of our General Partner to operate and manage our business.
If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results timely and accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.
We are subject to the public reporting requirements of the Exchange Act, including the rules thereunder that require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Effective internal controls are necessary for us to provide reliable and timely financial reports, prevent fraud and to operate successfully as a publicly traded partnership. We

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prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("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.
We are required to disclose changes made in our internal control and procedures on a quarterly basis and make an annual assessment of our internal control over financial reporting pursuant to Section 404. 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.
The amount of cash we have available for distribution to holders of our common units, subordinated units, and Series A convertible preferred units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.
Risks Inherent in an Investment in Us
Southcross Energy LLC owns and controls our General Partner, which has sole responsibility for conducting our business and managing our operations as well as has limited duties to us and our unitholders. Southcross Energy LLC and our General Partner have conflicts of interest with us and they may favor their own interests to the detriment of us and our other unitholders.
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:
Neither our Second Amended and Restated Agreement of Limited Partnership ("Partnership Agreement") nor any other agreement requires Southcross Energy LLC to pursue a business strategy that favors us.
Our General Partner is allowed to take into account the interests of parties other than us, such as Southcross Energy LLC, in resolving conflicts of interest.
Our Partnership Agreement replaces the fiduciary duties that would otherwise be owed by our General Partner to us and our unitholders with contractual standards governing its duties to us and our unitholders, limits our General Partner's liabilities, and also restricts the rights of our unitholders with respect to actions that, without the limitations, might constitute breaches of fiduciary duty.
Except in limited circumstances, our General Partner has the power and authority to conduct our business without unitholder approval.
Our General Partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

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Our General Partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or a growth capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our General Partner and the ability of the subordinated units to convert to common units.
Our General Partner determines which costs incurred by it are reimbursable by us.
Our General Partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.
Our Partnership Agreement permits us to classify up to $35.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our General Partner in respect of the general partner interest or the incentive distribution rights.
Our Partnership Agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.
Our General Partner intends to limit its liability regarding our contractual and other obligations.
Our General Partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.
Our General Partner controls the enforcement of the obligations that it and its affiliates owe to us.
Our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.
Our General Partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our General Partner's incentive distribution rights without the approval of the conflicts committee of the board of directors of our General Partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
Charlesbank is not limited in its ability to compete with us and is not obligated to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could adversely affect our results of operations and cash available for distribution to our unitholders.
Charlesbank is not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. 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.
The market price of our common units may fluctuate significantly, and you could lose all or part of your investment.
There were 10,390,272 publicly traded common units at December 31, 2013. In addition, Southcross Energy LLC owns 1,863,713 common units, 12,213,713 subordinated units and 221,884 Series A convertible preferred 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 quarterly distributions;
our quarterly or annual earnings or those of other companies in our industry;
the loss of a large customer;
announcements by us or our competitors of significant contracts or acquisitions;
changes in accounting standards, policies, guidance, interpretations or principles;
general economic conditions;
the failure of securities analysts to cover our common units or changes in financial estimates by analysts;
future sales of our common units; and
other factors described in these "Risk Factors."
Our General Partner intends to limit its liability regarding our obligations.
Our General Partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our General Partner or its assets. Our General Partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our General Partner. Our Partnership Agreement provides that any action taken by our General Partner to limit its liability is not a breach of our General Partner's fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our General Partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
Our Partnership Agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and growth 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 growth 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.
While our Partnership Agreement requires us to distribute all of our available cash, our Partnership Agreement, including provisions requiring us to make cash distributions contained therein, may be amended.
While our Partnership Agreement requires us to distribute all of our available cash, our Partnership Agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our Partnership Agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our Partnership Agreement can be amended with the consent of our General Partner and the approval of a majority of the outstanding common units (including common units held by affiliates of our General Partner) after the subordination period has ended. As of December 31, 2013, Southcross Energy LLC, the 100% owner of our General Partner, owned, directly or indirectly, 15.2% of the outstanding common units, all of our outstanding subordinated units and 12.5% of our outstanding Series A convertible preferred units.
Reimbursements due to our General Partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our common unitholders. The amount and timing of such reimbursements will be determined by our General Partner.

38


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 replaces our General Partner's fiduciary duties to holders of our common and subordinated units with contractual standards governing its duties.
Our Partnership Agreement contains provisions that eliminate the fiduciary duties to which our General Partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our Partnership Agreement permits our General Partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our General Partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the Partnership Agreement does not provide for a clear course of action. This entitles our General Partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our General Partner may make in its individual capacity include:
how to allocate corporate opportunities among us and its affiliates;
whether to exercise its limited call right;
whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our General Partner;
how to exercise its voting rights with respect to the units it owns;
whether to elect to reset target distribution levels;
whether to transfer the incentive distribution rights or any units it owns to a third party; and
whether or not to consent to any merger or consolidation of the Partnership or amendment to the Partnership Agreement.
By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the Partnership Agreement, including the provisions discussed above.
Our Partnership Agreement restricts the rights of holders of our common and subordinated units with respect to actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.
Our Partnership Agreement contains provisions that restrict the rights of unitholders with respect to actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our Partnership Agreement provides that:
whenever our General Partner makes a determination or takes, or declines to take, any other action in its capacity as our General Partner, our General Partner is required to make such determination, or take or decline to take such other action, in good faith, meaning it subjectively believed that the decision was in the best interest of us and our unitholders, and except as specifically provided by our Partnership Agreement, will not be subject to any other or different standard imposed by our Partnership Agreement, Delaware law, or any other law, rule or regulation, or at equity;
our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a General Partner so long as such decisions are made in good faith;
our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

39


our General Partner will not be in breach of its obligations under the Partnership Agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:
approved by the conflicts committee of the board of directors of our General Partner, although our General Partner is not obligated to seek such approval;
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our General Partner and its affiliates;
determined by the board of directors of our General Partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
determined by the board of directors of our General Partner to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our General Partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our General Partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the final two subclauses above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, 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 may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our General Partner's incentive distribution rights without the approval of the conflicts committee of our General Partner's board or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
Our General Partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election by our General Partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the "reset minimum quarterly distribution"), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
We anticipate that our General Partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our General Partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our General Partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our General Partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive 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 our 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.
Holders of our common units have limited voting rights and are not entitled to elect our General Partner or its directors.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders 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

40


General Partner, they will have little ability to remove our General Partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our Partnership Agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.
Even if holders of our common units are dissatisfied, they cannot currently remove our General Partner without its consent.
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, 2013, Southcross Energy LLC owns 54.5% of our outstanding common units, subordinated units and Series A convertible preferred 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 us will most likely result in the termination of the subordination period and the conversion of all subordinated units to common units.
Our Partnership Agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Unitholders' voting rights are further restricted by a provision of our Partnership Agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our General Partner, cannot vote on any matter.
Our General Partner interest or the control of our General Partner may be transferred to a third party without unitholder consent.
Our General Partner may transfer its General Partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our Partnership Agreement does not restrict the ability of 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.
We may issue additional units without your approval, which would dilute your existing ownership interests.
Our Partnership Agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
our existing unitholders' proportionate ownership interest in us will decrease;
the amount of cash available for distribution on each unit may decrease;
because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding unit may be diminished; and
the market price of the common units may decline.
Southcross Energy LLC may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

41


As of December 31, 2013, Southcross Energy LLC held an aggregate of 1,863,713 common units, 12,213,713 subordinated units, and 221,884 Series A convertible preferred units. All of the subordinated units will convert into common units at the end of the subordination period. The Series A convertible preferred units may be converted on a one-for-one basis, as adjusted, upon our election to apply certain leverage covenants set forth in our Credit Facility. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.
Our General Partner has a limited call right that may require you to sell your units at an undesirable time or price.
If at any time our General Partner and its affiliates own more than 80% of the common units, our General Partner will have the right, which it may assign to any of its affiliates or to us, but not the 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, 2013, Southcross Energy LLC owned approximately 15.2% of our 12,253,985 outstanding common units. At the end of the subordination period and following the conversion of the Series A convertible preferred units, assuming no additional issuances of common units (other than upon the conversion of the subordinated units and the Series A convertible preferred units), Southcross Energy LLC will own approximately 54.5% of our outstanding common units. Also, in February 2014, we completed a public offering of 9,200,000 additional common units.
Your liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to our general partner. We are organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:
we were conducting business in a state but had not complied with that particular state's partnership statute; or
your right to act with other unitholders to remove or replace our General Partner, to approve some amendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitute "control" of our business.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to us 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 our interest nor liabilities that are non-recourse to us are counted for purposes of determining whether a distribution is permitted.
Tax Risks
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service (IRS) were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.
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

42


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.
If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.
Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to 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.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect 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.
Unitholders' share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.
Because a unitholder will be treated as a partner to whom we will allocate taxable income 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.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. 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 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.
Tax gain or loss on the disposition of our common units could be more or less than expected.
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.

43


Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. 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.
We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we 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 prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We will prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. 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.
A unitholder whose common units are loaned to a "short seller" to effect a short sale of common units may be considered as having disposed of those common units. If so, such unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose common units are loaned to a "short seller" to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.
We will adopt certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our General Partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our General Partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our General Partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our General Partner and certain of our unitholders.

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A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders' sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ended 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 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, we will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.
As a result of investing in our common units, our unitholders may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently conduct business in Alabama, Mississippi, and Texas. 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:
1.
parcels that we own in fee title; and
2.    parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations.
Portions of the land on which our 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 Part I, Item 1 of this report and incorporated herein by reference.
Item 3.
Legal Proceedings

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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 currently are 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 ultimately will have a material effect on our results of operations, cash flows or financial condition in any future reporting periods.

On March 5, 2013, our subsidiary filed suit against Formosa Hydrocarbons Company, Inc. (“Formosa”).  The lawsuit seeks recoveries of losses that we believe our subsidiary experienced as a result of the failure of Formosa to perform certain obligations under the gas processing and sales contract between the parties.  Formosa filed a response generally denying our claims and, later, Formosa filed a counterclaim against our subsidiary claiming our affiliate breached the gas processing and sales contract and a related agreement between the parties for the supply by Formosa of residue gas to a third party on behalf of our subsidiary. We believe the counterclaims are without merit and our subsidiary will defend itself vigorously against the counterclaims while continuing to pursue our own claims. We cannot predict the outcome of such litigation or the timing of any related recoveries or payments.
 
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 NYSE since November 2, 2012 under the symbol "SXE." The table below sets forth the high and low sales prices of our common units and the per unit distributions declared since November 7, 2012. Distributions are recorded when paid.
 
Unit Prices
 
Distributions
per common unit
 
 
 
 
 
High
 
Low
 
 
Record date
 
Payment date
Quarter Ended December 31, 2013
$
21.00

 
$
16.21

 
$
0.40

 
February 5, 2014
 
February 14, 2014
Quarter Ended September 30, 2013
24.78

 
16.73

 
0.40

 
November 7, 2013
 
November 14, 2013
Quarter Ended June 30. 2013
23.67

 
18.34

 
0.40

 
August 9, 2013
 
August 14, 2013
Quarter Ended March 31, 2013
26.49

 
20.15

 
0.40

 
May 10, 2013
 
May 15, 2013
Quarter Ended December 31, 2012 (1)
24.75

 
22.00

 
0.24

(2) 
February 11, 2013
 
February 14, 2013
_______________________________________________________________________________
(1)
From November 2, 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 our 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 February 28, 2014 was $17.60 and, as of such date, there were approximately 5,831 holders of record of our common units and 21,454,119 common units outstanding. As of February 28, 2014, we have issued 12,213,713 subordinated units, 1,800,886 Series A convertible preferred units and 723,220 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, 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:
less the amount of cash reserves established by our General Partner at the date of determination of available cash for that quarter to:
provide for the proper conduct of our business (including reserves for our future capital expenditures and anticipated future credit needs);
comply with applicable law, any of our debt instruments or other agreements; or
provide funds for distributions to our unitholders and to our General Partner for any one or more of the next four quarters (provided that our General Partner may not establish cash reserves for distributions unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);
plus, if our General Partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.
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.    Commencing with the fourth quarter of 2012, we made quarterly distributions to the holders of our common units and subordinated units of $0.40 per unit, or $1.60 on an annualized basis (with the first such distribution being prorated), and intend to continue to make a minimum quarterly distribution to unitholders 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

47


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 2.0% of all distributions that we make prior to our liquidation. Our General Partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current General Partner interest. Our General Partner's initial 2.0% interest in our distributions will be reduced if we issue additional limited partner units in the future and our General Partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest.
Our General Partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50%, 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 2.0% general partner interest and assumes that our General Partner maintains its general partner interest at 2.0%. 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 2.0% general partner interest and assume that our General Partner has contributed any additional capital necessary to maintain its 2.0% general partner interest, our General Partner has not transferred its incentive distribution rights and that there are no arrearages on common units.
 
 
 
Marginal percentage interest
in distributions
 
Total quarterly distribution per
unit target amount
 
Unitholders
 
General Partner
Minimum quarterly distribution

$0.40

 
98
%
 
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
%
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, 2013, assuming an initial investment of $100.

48


Securities Authorized for Issuance Under Equity Compensation Plan
See discussion in Part III, Item 12 of this report entitled “Securities Authorized for Issuance Under Equity Compensation Plan.”



49


Item 6.
Selected Financial Data
The information in this section should be read in conjunction with Part II, Item 7 and Item 8. 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 (in thousands, except per unit data and volume data).
 
Year Ended December 31,
 
June 2, 2009 through December 31, 2009(1)
 
Southcross Energy LLC's Predecessor
 
2013(1)
 
2012(1)
 
2011(1)
 
2010(1)
 
 
January 1, 2009 through July 31, 2009
Statements of operations data:

 

 

 

 

 

Revenues
$
634,722

 
$
496,129

 
$
523,149

 
$
498,747

 
$
206,634

 
$
330,870

(Loss) income from operations
(3,020
)
 
3,289

 
16,388

 
19,733

 
9,325

 
1,798

Net loss
(15,970
)
 
(4,488
)
 

 

 

 

Series A convertible preferred unit in-kind distribution and fair value adjustment
(1,670
)
 

 

 

 

 

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

 
(260
)
 

 

 

 

Net loss for partners
(17,640
)
 
(4,228
)
 

 

 

 

General partner's interest
(319
)
 
(85
)
 

 

 

 

Limited partners' interest
(17,321
)
 
(4,143
)
 

 

 

 

Net (loss) income from Southcross Energy LLC

 
(260
)
 
7,539

 
9,719

 
4,408

 
1,721

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) income 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)
(8,683
)
 
(2,072
)
 

 

 

 

Weighted average number of limited partner common units outstanding
12,224,997

 
12,213,713

 

 

 

 

Loss per common unit
(0.71
)
 
(0.17
)
 

 

 

 

Net (loss) income 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)
1.60

 
0.24

 
n/a

 
n/a

 
n/a

 
n/a

Other financial data:

 

 

 

 

 

Adjusted EBITDA(4)
34,486

 
24,019

 
28,957

 
30,869

 
16,517

 
9,236

Gross operating margin(4)
93,546

 
71,640

 
62,569

 
59,316

 
27,589

 
29,502

Maintenance capital expenditures
3,353

 
5,193

 
5,317

 
3,402

 
3,025

 
565

Growth capital expenditures
90,510

 
164,623

 
150,669

 
1,843

 
1,669

 
250

Operating data:

 

 

 

 

 

Average throughput volumes of natural gas (MMBtu/d)
575,240

 
553,093

 
506,975

 
471,265

 
492,350

 
592,243

Average volume of processed gas (MMBtu/d)
240,825

 
206,045

 
155,475

 
153,557

 
166,018

 
188,642

Average volume of NGLs sold (Bbls/d)
12,545

 
9,385

 
5,131

 
5,557

 
5,369

 
5,757

Realized prices on natural gas volumes sold/Btu ($/MMBtu)
3.75

 
2.83

 
4.05

 
4.42

 
3.97

 
3.95

Realized prices on NGL volumes sold/gal ($/gal)
0.88

 
0.87

 
1.35

 
1.10

 
1.01

 
0.69

Balance sheet data (at period end):

 

 

 

 

 

Cash and cash equivalents
3,349

 
7,490

 
1,412

 
20,323

 
5,724

 

Trade accounts receivable
57,669

 
50,994

 
41,234

 
35,059

 
39,956

 

Property, plant, and equipment, net
575,795

 
550,603

 
369,861

 
229,309

 
235,065

 

Total assets
652,315

 
618,605

 
420,385

 
289,643

 
287,808

 

Total debt (current and long term)
267,300

 
191,000

 
208,280

 
115,000

 
119,949

 

Series A convertible preferred unit in-kind distribution and fair value adjustment
40,504

 

 

 

 

 

_______________________________
(1)
Reflects financial data of Southcross Energy Partners, L.P. subsequent to our IPO on November 7, 2012, and Southcross Energy LLC for periods ending prior to November 7, 2012.
(2)
Earnings per unit of Southcross Energy LLC prior to our IPO of Southcross Energy Partners, L.P.
(3)
A distribution of $0.24 attributable to fourth quarter 2012 is the first distribution declared by us 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 our IPO on November 7, 2012.
(4)
See Part II, Item 7 for definition of Non-GAAP financial metrics and reconciliation of Non-GAAP metrics to its most directly comparable GAAP financial measure.

50


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.
Overview and How We Evaluate our Operations
Overview
Southcross Energy Partners, L.P. (the "Partnership," "Southcross," "we," "our" or "us") 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, when used for periods prior to our initial public offering ("IPO") on November 7, 2012, refer to Southcross Energy LLC and its consolidated subsidiaries, unless otherwise specifically noted. References in this Form 10-K to the Partnership, when used for periods beginning at or following our IPO, refer collectively to the Partnership and its consolidated subsidiaries. Southcross Energy LLC and its subsidiaries are controlled through investment funds and entities associated with Charlesbank Capital Partners, LLC ("Charlesbank"). Southcross Energy LLC holds all of the equity interests in Southcross Energy Partners GP, LLC, a Delaware limited liability company and our general partner (“General Partner”).
We are a master limited partnership that provides natural gas gathering, processing, treating, compression and transportation services and NGL fractionation and transportation services. We also source, purchase, transport and sell natural gas and NGLs. Our assets are located in South Texas, Mississippi and Alabama and include three gas processing plants, two fractionation plants and approximately 2,740 miles of pipeline. Our South Texas assets are located in or near the Eagle Ford shale region. We are headquartered in Dallas, Texas.
General Trends and Outlook

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 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.

Natural Gas and NGL Environment

According to the U.S. Energy Information Administration (the “EIA”) natural gas production in the United States reached its highest recorded annual total in 2013 and is expected to increase from 23 trillion cubic feet (“Tcf”) in 2011 to 33 Tcf in 2040, with almost all of the growth coming from shale formations. Natural gas production from shales is expected to increase to 19 Tcf by 2040 from 5 Tcf produced in 2010. Natural gas production from shales amounted to 23% of total natural gas produced in the U.S. in 2010 and is projected to grow to 56% by 2040. The continued growth in shale gas production is expected to result from the dual application of horizontal drilling and hydraulic fracturing. Another contributing factor is ongoing drilling in shale and other plays with high concentrations of NGLs and crude oil, which in energy-equivalent terms, have a higher value than dry natural gas.

The increase in natural gas consumption in the U.S. is expected to come primarily from the industrial and electric power sectors. Major consumers of natural gas in the United States in 2012 included the electric power generation sector with consumption of 9 Tcf, the industrial sector with 7 Tcf, the residential sector with 4 Tcf and 3 Tcf from the commercial sector. The natural gas share of electricity generation rose to 24% in 2010 and is expected to continue increasing to 30% in 2040, driving a large portion of the anticipated increased consumption of natural gas in the United States.

As a result of the current low natural gas price environment, some natural gas producers have cut back or suspended their drilling operations in certain dry gas regions where the economics of natural gas production are less favorable. Drilling activities focused in liquids-rich regions have continued and, in some cases, have increased, as the high Btu content associated with liquids-rich production enhances overall drilling economics, even in a low natural gas price environment.


51


Average daily gas production in the Eagle Ford in South Texas reached 3.3 Bcf/d in 2013, 54% higher than in 2012. According to the Texas Railroad Commission, well permits increased from 2011 to 2013 in the Eagle Ford shale region by approximately 45% from 2,826 to 4,107 permitted. With continued growth of drilling activity and gas production in South Texas and the Eagle Ford shale area, we believe there will continue to be expansion opportunities for ourselves and other midstream companies in order to meet the growing infrastructure needs of our customers and continue to move natural gas and NGLs to markets.

We expect that the continued environment for natural gas demand will be favorable, driven by population, economic growth, and the export market, as well as the continued replacement of coal electricity generation by natural gas electricity generation due to the low prices of natural gas and stricter governmental and environmental regulations on the mining and burning of coal.

According to EIA forecasts, the United States will become a net exporter of liquid natural gas (“LNG”) in 2016, and it an overall net exporter of natural gas in 2018. U.S. exports of LNG from new liquefaction capacity are expected to surpass 2 Tcf by 2020 and increase to 3.5 Tcf in 2029.

Interest rate environment

The credit markets recently have experienced near-record lows in interest rates. As the overall economy strengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. This could affect our ability to access the debt capital markets to the extent we may need to in the future to fund our growth. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Although this could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.
Our Operations
Our integrated operations provide a full range of complementary services extending from wellhead to market, including gathering natural gas at the wellhead, treating natural gas to meet downstream pipeline and customer quality standards, processing natural gas to separate NGLs from natural gas, fractionating the resulting NGLs into the various components and selling or delivering pipeline quality natural gas and purity product NGLs to various industrial and energy markets as well as large pipeline systems. Through our network of pipelines, we connect supplies of natural gas to our customers, which include industrial, commercial and power generation customers and local distribution companies. All of our operations are managed as and presented in one reportable segment.
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 with the goal 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 several 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 to provide service to our customers. We purchase, gather, process, treat, compress, transport and sell natural gas and purchase, fractionate, transport and sell NGLs. Contracts with a counterparty generally contain one or more of the following arrangements:
Fixed-Fee.  We receive a fixed-fee per unit of natural gas volume that we gather at the wellhead, process, treat, compress and/or transport for our customers, or we receive a fixed-fee per unit of NGL volume that we fractionate. Some of our arrangements also provide for a fixed-fee for guaranteed transportation capacity on our systems.
Fixed-Spread.  Under these arrangements, we purchase natural gas and NGLs from producers or suppliers at receipt points on our systems at an index price plus or minus a fixed price differential and sell these volumes of natural gas and NGLs at delivery points off our systems at the same index price, plus or minus a fixed price differential. By entering into such back-to-back purchases and sales, we are able to mitigate our risk associated with changes in the general commodity price levels of natural gas and NGLs. We remain subject to variations in our fixed-spreads to the extent we are unable to precisely match volumes purchased and sold in a given time period or are unable to secure the supply or to produce or market the necessary volume of products at our anticipated differentials to the index price.
Commodity-Sensitive.  In exchange for our processing services, we may remit to a customer a percentage of the proceeds from our sales, or a percentage of the physical volume, of residue natural gas and/or NGLs that result from our natural gas processing, or we may purchase NGLs from customers at set fixed NGL recoveries and retain the balance of the proceeds or physical commodity for our own account. These arrangements are generally combined with

52


fixed-fee and fixed-spread arrangements for processing services and, therefore, represent only a portion of a processing contract's value. The revenues we receive from these arrangements directly correlate with fluctuating general commodity price levels of natural gas and NGLs and the volume of NGLs recovered relative to the fixed recovery obligations.
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 and NGLs 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.
The following table summarizes our gross margins from these arrangements (in thousands):

 
Year ended December 31,
 
2013
 
2012
 
2011
 
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
$
59,532

 
63.7
%
 
$
48,055

 
67.0
%
 
$
32,340

 
51.7
%
Fixed-spread
11,143

 
11.9
%
 
18,737

 
26.2
%
 
14,544

 
23.2
%
Sub-total
70,675

 
75.6
%
 
66,792

 
93.2
%
 
46,884

 
74.9
%
Commodity-sensitive
22,871

 
24.4
%
 
4,848

 
6.8
%
 
15,685

 
25.1
%
Total gross operating margin
$
93,546

 
100.0
%
 
$
71,640

 
100.0
%
 
$
62,569

 
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 on a disaggregated basis, 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 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 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, property ad valorem 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 and distributable cash flow are widely accepted financial indicators of our operational performance and our ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA and distributable cash flow are not measures calculated in accordance with GAAP.
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 and unrealized losses on derivative contracts, major

53


litigation, net of recoveries, 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:
the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions;
operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and
the attractiveness of capital projects and acquisitions and the overall rates of return on investment opportunities.
We define distributable cash flow as Adjusted EBITDA plus interest income, less cash paid for interest (net of capitalized costs), income tax expense 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:
the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders; and
the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.
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, results of operations and cash flows from 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,
 
2013
 
2012
 
2011
Gross operating margin
$
93,546

 
$
71,640

 
$
62,569

Add (deduct):
 
 
 
 
 
Income tax expense
(385
)
 
(246
)
 
(261
)
Interest expense
(12,590
)
 
(5,767
)
 
(5,348
)
Loss on extinguishment of debt

 
(1,764
)
 
(3,240
)
Gain on sale of assets, net
25

 

 
522

General and administrative expense
(21,764
)
 
(13,842
)
 
(9,129
)
Depreciation and amortization expense
(33,548
)
 
(18,977
)
 
(12,345
)
Operations and maintenance expense
(41,254
)
 
(35,532
)
 
(25,229
)
Net (loss) income
$
(15,970
)
 
$
(4,488
)
 
$
7,539



54










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):

55


 
Year ended December 31,
 
2013
 
2012
 
2011
 
 
 
 
 
 
Net cash provided by operating activities
$
15,973

 
$
24,323

 
$
20,007

Add (deduct):

 

 

Depreciation and amortization expense
(33,548
)
 
(18,977
)
 
(12,345
)
Unit-based compensation
(2,186
)
 
(630
)
 

Loss on extinguishment of debt

 
(1,764
)
 
(3,240
)
Deferred financing costs amortization
(1,287
)
 
(1,183
)
 
(882
)
Gain on sale of assets, net
25

 

 
522

Unrealized gain (loss)
120

 
(141
)
 
(21
)
Other, net
(130
)
 

 

Changes in operating assets and liabilities:

 

 

Trade accounts receivable
6,675

 
9,760

 
2,806

Prepaid expenses and other
1,197

 
1,246

 
497

Other non-current assets
(215
)
 
(1,786
)
 
2,155

Accounts payable and accrued expenses
(1,411
)
 
(16,517
)
 
(2,759
)
Other liabilities
(1,183
)
 
1,181

 
799

Net (loss) income
$
(15,970
)
 
$
(4,488
)
 
$
7,539

Add (deduct):
 
 
 
 
 
Depreciation and amortization expense
33,548

 
18,977

 
12,345

Interest expense
12,590

 
5,767

 
5,348

Unrealized (gain) loss
(120
)
 
141

 
21

Loss on extinguishment of debt

 
1,764

 
3,240

Unit-based compensation
2,186

 
630

 

Income tax expense
385

 
246

 
261

Gain on sale of assets, net
(25
)




Major litigation costs, net of recoveries
517





Other, net
61

 
568

 
203

Expenses associated with significant items
1,314

 
414

 

Adjusted EBITDA
$
34,486

 
$
24,019

 
$
28,957

(Deduct):
 
 
 
 
 
Cash interest, net of capitalized costs
(11,187
)
 
(4,584
)
 
(4,466
)
Income tax expense
(385
)
 
(246
)
 
(261
)
Maintenance capital expenditures
(3,353
)
 
(5,193
)
 
(5,317
)
Distributable cash flow
$
19,561

 
$
13,996

 
$
18,913

Current Year Highlights
The following events that took place during 2013 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 of this report for a more detailed account of such events.
Financing Activities
Credit Facility
On March 27, 2013 we entered into the first amendment (the “First Amendment”) to our Credit Facility. On April 12, 2013, we entered into the limited waiver and second amendment (the “Second Amendment”) to our Credit Facility, which waived our defaults under our Credit Facility relating to financial covenants for the period ended March 31, 2013 and provided us with more favorable financial covenants than were provided previously. On January 29, 2014, we entered into the third

56


amendment (the “Third Amendment") to our Credit Facility. Pursuant to the Third Amendment, we may acquire a specified target entity or its assets, and make certain capital expenditures with respect to the extension of the Partnership’s pipeline systems located in McMullen County, Texas.
Series A Convertible Preferred Units
We entered into a Series A Convertible Preferred Unit Purchase Agreement (the “Purchase Agreement”) with Southcross Energy LLC, pursuant to which we issued and sold 1,715,000 of our Series A convertible preferred units ("Series A Preferred Units") to Southcross Energy LLC during the second quarter of 2013. The Series A Preferred Units were sold to Southcross Energy LLC for a cash purchase price of $22.86 per unit, in a privately negotiated transaction (the “Private Placement”). Southcross Energy LLC sold 1,500,000 of these Series A Preferred Units to third parties during the second quarter of 2013. At December 31, 2013, Southcross Energy LLC held 221,884 Series A Preferred Units.  In our S-3 Registration Statement filed on November 29, 2013, the common units issuable upon conversion of our Series A Preferred Units were registered. See further discussion included in Part II, Item 8, Note 10 of this report.

The $40.0 million raised from all sales of Series A Preferred Units and General Partner capital contributions was used to reduce borrowings under our Credit Facility (See Part II, Item 8, Note 7). The Private Placement of Series A Preferred Units resulted in proceeds to us of $39.2 million, and our General Partner contributed $0.8 million to maintain its 2.0% general partner interest in us.

Applicable accounting guidance related to the Series A Preferred Units requires that equity instruments with redemption features that are redeemable at the option of the holder be classified outside of permanent equity. The change of control rights associated with the Series A Preferred Units require the units to be classified outside of permanent equity. Additionally, none of the identified embedded derivatives relating to the terms of the Series A Preferred Units requires bifurcation, as each embedded derivative was determined to be clearly and closely related to the host contract.
Key Factors Affecting Operating Results and Financial Condition 
Bonnie View NGL fractionation facility. In February 2013, we completed the expansion of NGL fractionation capacity at our Bonnie View fractionation facility, increasing its capacity to 22,500 Bbls/d.  The plant initiated operations in November 2012 with capacity of 11,500 Bbls/d.  The plant fractionates y-grade NGLs from our Woodsboro processing plant and produces NGL component products. 

Bonnie View start-up lost revenue and expenses. Following the start-up of our Bonnie View fractionation facility during the fourth quarter of 2012, we experienced periods of reduced recoveries and production of off-specification NGLs. This continued into the six-month period ended June 30, 2013, which caused us to sell non-purity products at reduced prices or leave NGLs in the natural gas stream and sell them at natural gas equivalent prices.  The plant achieved consistent operating performance commencing later in the quarter ended June 30, 2013, and during the quarters ended September 30, 2013 and December 31, 2013, in excess of 99% of finished NGLs produced at our two fractionators were sold at “on-spec” prices.

New pipelines in operation. In February 2013, we completed construction and commenced full flow-through of our 20-inch Bee Line pipeline to move rich gas to our Woodsboro processing plant. The Bee Line is a 57-mile pipeline with capacity of approximately 320 MMcf/d. In July 2013, we commenced flow-through of our new 16-inch, 9.4-mile pipeline from our Karnes County pipeline into Bee County. In October 2013, we initiated operation of a new 12-inch, 3.3-mile pipeline lateral off of our McMullen pipeline to move rich gas to our Woodsboro processing plant.

Gregory processing and NGL fractionation facility.  We shut down the Gregory facility in January 2013 to perform extensive turnaround maintenance activities and connect additional equipment to enhance NGL recoveries.  As the turnaround maintenance was nearing completion in January 2013, we experienced a fire that damaged a small portion of the facility. We resumed significant operations in April 2013 and full operations in May 2013.  In connection with the fire, we spent $4.6 million to return the plant to service and filed an insurance claim related to these costs.  We recovered $1.0 million from insurance for this loss during the second quarter of 2013 and believe it is probable that we will recover the remaining costs, less a $0.3 million deductible, under our insurance policies. 

New long-term NGL sales contracts.  In March 2013, we entered into new firm sales contracts for propane, butane and natural gasoline produced at both our Bonnie View and Gregory NGL fractionation facilities. Deliveries under these contracts began in May 2013, providing us with additional markets at fixed differentials to NGL index prices and enhancing our earnings. 

57


Results of Operations
The following table summarizes our results of operations (in thousands, except operating data):
 
Year ended December 31,
 
2013
 
2012
 
2011
Revenues
$
634,722

 
$
496,129

 
$
523,149

Expenses:

 

 

Cost of natural gas and liquids sold
541,176

 
424,489

 
460,580

Operations and maintenance
41,254

 
35,532

 
25,229

Depreciation and amortization
33,548

 
18,977

 
12,345

General and administrative
21,764

 
13,842

 
9,129

Total expenses
637,742

 
492,840

 
507,283

(Loss) income from operations
(3,020
)
 
3,289

 
15,866

Loss on extinguishment of debt

 
(1,764
)
 
(3,240
)
Gain on sale of assets, net
25

 

 
522

Interest expense
(12,590
)
 
(5,767
)
 
(5,348
)
(Loss) income before income tax expense
(15,585
)
 
(4,242
)
 
7,800

Income tax expense
(385
)
 
(246
)
 
(261
)
Net (loss) income
$
(15,970
)
 
$
(4,488
)
 
$
7,539

Other financial data:
 
 
 
 
 
Adjusted EBITDA
$
34,486

 
$
24,019

 
$
28,957

Gross operating margin
93,546

 
71,640

 
62,569

Maintenance capital expenditures
3,353

 
5,193

 
5,317

Growth capital expenditures
90,510

 
164,623

 
150,669

Operating data:
 
 
 
 
 
Average throughput of gas (MMBtu/d)
575,240

 
553,093

 
506,975

Average volume of processed gas (MMBtu/d)
240,825

 
206,045

 
155,475

Average volume of NGLs sold (Bbls/d)
12,545

 
9,385

 
5,131

Realized prices on natural gas volumes ($/MMBtu)
$
3.75

 
$
2.83

 
$
4.05

Realized prices on NGL volumes ($/gal)
0.88

 
0.87

 
1.35

The following table summarizes our average natural gas throughput volumes, amount of NGLs delivered, and volume of processed gas:
 
Year ended December 31,
 
2013
 
2012
 
2011
Average throughput volumes of natural gas (MMBtu/d)
 
 
 
 
 
South Texas
375,777

 
352,458

 
363,545

Mississippi/Alabama
199,463

 
200,635

 
143,430

Total average throughput volumes of natural gas
575,240

 
553,093

 
506,975

Average volume of processed gas (MMBtu/d)
240,825

 
206,045

 
155,475

Average volume of NGLs sold (Bbls/d)
12,545

 
9,385

 
5,131

2013 Compared with 2012
Volume and overview—Our average throughput volume of natural gas increased by 4.0% to 575,240 MMBtu/d in 2013 compared to 553,093 MMBtu/d in 2012, including an increase of 6.6% in our South Texas volumes. The increase was driven primarily by increased rich gas volumes entering our pipelines in South Texas to be processed at our facilities.  Processed gas volumes increased 16.9% to 240,825 MMBtu/d during 2013, compared to 206,045 MMBtu/d during 2012 as a result of

58


increased processing capacity during 2013 at our Woodsboro processing plant which was completed during the last half of 2012. The average volume of NGLs sold increased by 33.7% to 12,545 Bbls/d in 2013 primarily the result of an increase in rich gas volumes processed at our facilities from the Eagle Ford shale area.  Fractionation capacity of our Bonnie View fractionation facility increased from 11,500 Bbls/day during the last half of 2012 to 22,500 Bbls/day in February 2013. 
Our gross operating margin increased by 30.6% to $93.5 million in 2013 compared to $71.6 million in 2012. This increase was due primarily to increased margin from NGLs and revenues from transportation, gathering and processing fees related to higher processed gas volumes.
We incurred a net loss of $16.0 million in 2013 compared to a net loss of $4.5 million in 2012. This was due primarily to a $14.6 million increase in depreciation and amortization expense, a $7.9 million increase in general and administrative expenses, a $6.8 million increase in interest expense and higher operations and maintenance expenses of $5.7 million partially offset by an increase in gross margin of $21.9 million. Adjusted EBITDA increased 43.6% to $34.5 million in 2013 compared to $24.0 million in 2012. This was due primarily to higher gross operating margin partially offset by increased general and administrative expenses and operations and maintenance expenses.
Revenue—Our revenue for 2013 increased 27.9% to $634.7 million compared to $496.1 million in 2012. The increase was due primarily to a $79.8 million increase in revenue from sales of natural gas to $405.2 million for 2013 compared to $325.4 million for 2012 resulting from increased natural gas sales volumes.  Additionally, revenue from sales of NGLs and condensate increased $45.4 million, or 36.6%, to $169.5 million for 2013, compared to $124.1 million for 2012, reflecting the increased production of NGLs at our plants. Additionally, revenue from transportation, gathering and processing fees increased $13.3 million, or 28.8%, reflecting the results of additional rich gas volumes in 2013.  Realized average natural gas and NGL prices were as follows: 
 
Years Ended December 31,
 
2013
 
2012
Natural Gas
$3.75/MMBtu
 
$2.83/MMBtu
NGLs
$0.88/gal
 
$0.87/gal
Cost of natural gas and NGLs sold—Our cost of natural gas and liquids sold was $541.2 million in 2013 compared to $424.5 million in 2012. The $116.7 million or 27.5% increase was due primarily to higher prices for natural gas and NGLs purchased and increased volumes of natural gas purchased compared to 2012.
Operations and maintenance expense—Operations and maintenance expense increased $5.7 million or 16.1% to $41.3 million in 2013 compared to $35.5 million in 2012. The increase was due primarily to higher labor and benefits of $2.5 million and an increase of $2.2 million for utilities associated with our Woodsboro plant and Bonnie View fractionation facility which commenced operations in the third quarter and fourth quarter of 2012, respectively. In addition, we had increased ad valorem and other taxes of $1.5 million during 2013 due to investments in and expansion of our assets which were partially offset by a reduction in operating expenses of $1.2 million associated with the operations of our pipeline assets due to a reduction in scheduled maintenance during 2013.
General and administrative ("G&A") expense—G&A expenses were $21.8 million in 2013 compared to $13.8 million in 2012 representing an $7.9 million or 57.2% increase. This increase was due primarily to increased expenses from additional personnel at our corporate office, expenses related to being a public company, insurance coverage to support our growing asset base and operations, and increased legal expenses associated with ongoing litigation.
Depreciation and amortization expense—Depreciation and amortization expense was $33.5 million for 2013 compared to $19.0 million in 2012 representing an increase of $14.6 million or 76.8%. The increase was due primarily to the timing of completion of growth capital projects and the acceleration of $1.3 million in depreciation related to the planned abandonment of a compressor station during 2013.
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.
Interest expense—Net interest expense increased $6.8 million, or 118.3%, to $12.6 million in 2013 compared to $5.8 million in 2012. The increase was due to higher average borrowings of $243.9 million in 2013 compared to $230.4 million in 2012. For the years 2013 and 2012, our average effective interest rate was 4.44% and 3.95%, respectively.
2012 Compared with 2011

59


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 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.
We 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 $10.3 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. Realized average natural gas and NGL prices were as follows: 
 
Years Ended December 31,
 
2012
 
2011
Natural Gas
$2.83/MMBtu
 
$4.05/MMBtu
NGLs
$0.87/gal
 
$1.35/gal
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 $10.3 million or 40.8% 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") expenses—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 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,

60


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 was 3.95% and 3.58%, respectively.
Liquidity and Capital Resources
Sources of Liquidity
Our primary sources of liquidity have been cash generated from operations, investments by Southcross Energy LLC and other investors, equity raised through our IPO and other equity issuances and borrowings under our predecessor’s credit facility and our Credit Facility. Our primary cash requirements consist of operating and G&A expenses, maintenance capital expenditures to sustain existing operations or generate additional revenues, interest payments on outstanding debt, acquisitions and construction of new assets, businesses acquisitions, and distributions to unitholders.
We expect to fund short term cash requirements, such as operating and G&A expenses and maintenance capital expenditures 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. Other than our new pipeline to be constructed that will extend in Webb County, Texas with estimated project cost of $125.0 million, our ability to fund expansion projects under our Credit Facility is currently limited to $25.0 million for the 18-month period ending June 30, 2015, which can be increased to $28.0 million if additional funds are placed into the Collateral Account (as defined in the Second Amendment). We entered into the Third Amendment to our Credit Facility in January 2014, which enables us to make certain capital expenditures with respect to the extension of our pipeline systems located in McMullen County, Texas in excess of the $25.0 million limitation for the18-month period ending June 30, 2015. See "Credit Facility" section below for a description of the amendments to our Credit Facility.
As of December 31, 2013, we had $267.3 million in outstanding borrowings under our Credit Facility. Under our Credit Facility, we have the ability to borrow $250.0 million plus an amount equal to the funds deposited into the Collateral Account and letters of credit outstanding. As of December 31, 2013, cash on deposit in the Collateral Account was $17.4 million. As of December 31, 2013, Southcross Energy LLC had $30.1 million of cash which has been made available for deposit into the Collateral Account to support subsequent additional borrowings. In February 2014, we completed a public equity offering of 9,200,000 additional common units and we received a capital contribution from our General Partner to maintain its 2.0% interest in us. The net proceeds from the public offering were $148.5 million.
We temporarily repaid borrowings under our Credit Facility, which we will redraw to fund the construction of new pipeline and other general purposes, including future permitted acquisitions.
Capital expenditures.    Our 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:
maintenance capital expenditures, which are capital expenditures that are not considered growth capital expenditures; and
growth capital expenditures, which are capital expenditures to expand or increase the efficiency of the existing operating capacity of our assets. Growth capital expenditures include expenditures that facilitate an increase in volumes within our operations, whether through construction or acquisition.

The following table summarizes our capital expenditures (in thousands):
 
 
Year Ended December 31,
 
2013
 
2012
Maintenance capital
$
3,353

 
$
5,193

Growth capital
90,510

 
164,623

Capital expenditures
$
93,863

 
$
169,816


Growth capital expenditures during the year ended December 31, 2013 related primarily to (i) our new pipeline laterals, (ii) completion and upgrades of the Bonnie View NGL fractionation facility in February 2013 and upgrades to the Woodsboro plant throughout 2013 and (iii) completion of our new Bee Line pipeline completed in February 2013.  Our growth capital expenditures during year ended December 31, 2012 related primarily to (i) construction of the Bonnie View fractionation facility (ii) construction of our Woodsboro processing facility and (iii) construction of the Bee Line pipeline. Our growth capital expenditures are estimated to be between $130.0 million to $150.0 million for 2014, including an estimated $125.0 million for the construction of the new pipeline extending into Webb County, Texas.

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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. Our ability to benefit from growth projects to accommodate strong drilling activity and the associated need for infrastructure assets and services 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 under performance 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. 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 our ability to comply with our debt covenants would likewise be affected adversely if we experienced declining volumes over a sustained period and/or 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 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 of December 31, 2013, we were in compliance with our financial covenants.
On January 29, 2014, we entered into the Third Amendment to our Credit Facility. Pursuant to the Third Amendment, we may acquire a specified target entity or its assets, and make certain capital expenditures with respect to the extension of the Partnership’s pipeline systems located in McMullen County, Texas.
In February 2014, we completed a public equity offering of 9,200,000 additional common units and we received a capital contribution from our General Partner to maintain its 2.0% interest in us. The net proceeds from the public offering were $148.5 million. We plan to use the net proceeds from the offering to fund the recently announced construction of our new pipeline extending into Webb County, Texas and for general partnership purposes, including future permitted acquisitions. Pending such use, we temporarily repaid borrowings under our Credit Facility, which we will redraw to fund the construction of the new pipeline and other general purposes. Also, under the terms of the Third Amendment to our Credit Facility, we amended our Consolidated Total Leverage Ratio (as defined in our Credit Facility) covenant in our Credit Facility to decrease automatically our “Maximum Adjusted Consolidated Total Leverage Ratio” (as defined in our Credit Facility) to 5.75 to 1.00.
We believe that cash from operations, the proceeds from our offering, cash on hand and available capacity under our Credit Facility will provide liquidity to meet future short term capital requirements and to fund committed capital expenditures for the majority of 2014. The sufficiency of these liquidity sources to fund necessary and committed capital needs will be dependent upon our ability to meet our covenant requirements of our Credit Facility. Please read "Liquidity and Capital Resources—Credit Facility" for a description of our Credit Facility.
Organic expansion projects and acquisitions are key elements of our business strategy. We intend to finance our 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.
Cash Flows
The following table provides a summary of our cash flows by category (in thousands):
 
Year ended December 31,
 
2013
 
2012
 
2011
Net cash provided by operating activities
$
15,973

 
$
24,323

 
$
20,007

Net cash used in investing activities
(97,109
)
 
(169,816
)
 
(144,602
)
Net cash provided by financing activities
76,995

 
151,571

 
105,684


62


2013 Compared with 2012
Operating Activities—Net cash provided by operating activities was $16.0 million in 2013, compared to $24.3 million in 2012. The decrease in cash provided by operating activities was $8.4 million. The net loss in 2013 was more than offset by non-cash charges in 2013, principally depreciation expense, resulting in positive cash flows from operations before working capital items of $22.4 million. Working capital needs were higher in 2013 due primarily to the 2013 payment of accrued capital expenditures in 2012 and an increased accounts receivable balance.
Investing Activities—Net cash used in investing activities was $97.1 million in 2013 compared to $169.8 million in 2012. The decrease in cash used in investing activities of $72.7 million primarily relates to the decrease in capital spending period over period caused by the completion of the Bee Line and Bonnie View fractionation facility in February 2013. During the year ended December 31, 2013, we spent $90.5 million in growth capital and $3.4 million in maintenance capital, compared to the year ended December 31, 2012 when we spent $164.6 million in growth capital and $5.2 million in maintenance capital.  In addition to capital spending, we spent $3.4 million, net of our insurance proceeds and deductible, at our Gregory facility related to a fire that occurred in January 2013 to return the plant to service.
Financing Activities—Net cash provided by financing activities was $77.0 million in 2013 compared to $151.6 million in 2012. The decrease was driven primarily by the proceeds from the issuance of common units from our IPO of $187.8 million and the proceeds from our predecessor's issuance of Series B redeemable preferred units and Series C redeemable preferred units of $42.8 million and $30.0 million, respectively, for the year ended December 31, 2012. This was offset by an increase in net borrowings of $93.6 million period over period and the issuance of our Series A Preferred Units increased cash from financing activities by $38.8 million for the year ended December 31, 2013
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 $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 growth 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 2011. 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.
Credit Facility
On January 29, 2014, we entered into the Third Amendment (the “Third Amendment”) to our Credit Facility which amends our "Consolidated Total Leverage Ratio" covenant to decrease automatically our “Maximum Adjusted Consolidated Total Leverage Ratio” to 5.75 to 1.00 if before March 31, 2014 we have (a) received net cash proceeds in a specified amount pursuant to permitted equity offerings and (b) initiated construction of the a new pipeline into Webb County, Texas in accordance with the terms of our Credit Facility (as defined in our Credit Facility).

As of December 31, 2013, we had $267.3 million in outstanding borrowings under our Credit Facility. Our Credit Facility matures on November 7, 2017, the fifth anniversary of our IPO closing date. We may utilize our Credit Facility for working capital requirements and capital expenditures, the purchase of assets, the payment of distributions, repurchase of units, specific acquisitions, and for our general purpose as long as we are in compliance with its terms, including our financial covenants. We have not experienced any difficulties in obtaining funding from any of our lenders, but the lack of or delay in funding by one or more members of our banking group could negatively affect our liquidity position.
Under our Credit Facility, we have the ability to borrow $250.0 million plus an amount equal to the funds deposited into the Collateral Account and letters of credit outstanding. As of December 31, 2013, cash on deposit in the Collateral Account was $17.4 million. Our borrowings under our Credit Facility were $267.3 million and $191.0 million as of December 31, 2013 and 2012, respectively, and our remaining available capacity under our Credit Facility was $0.1 million as of December 31, 2013. As of December 31, 2013, Southcross Energy LLC had $30.1 million of cash which has been made available for deposit into the Collateral Account to support subsequent additional borrowings. For the year ended December 31, 2013 and 2012, our average outstanding borrowings were $243.9 million and $230.4 million and our maximum outstanding borrowings were

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$267.3 million and $270.0 million, respectively. Our letters of credit outstanding were $31.3 million and $26.3 million as of December 31, 2013 and 2012, respectively. All of our assets are pledged as collateral under our Credit Facility.
Borrowings under our Credit Facility 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, the applicable margin under LIBOR borrowings was 4.50% and 3.25% at December 31, 2013 and 2012, respectively. The weighted average interest rate on borrowings under our Credit Facility for 2013 and 2012 was 4.44% and 3.95%, respectively. The commitment fee for both years ended December 31, 2013 and 2012 was $0.4 million.
On March 27, 2013, we entered into the First Amendment to our 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 our 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 to our 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 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:
the lenders waived defaults relating to financial covenants for the quarter ending March 31, 2013;
an increase in our letters of credit sublimit from $31.5 million to $50.0 million;
an increase in our interest rate to be the London Interbank Offered Rate ("LIBOR") plus 4.50% until the Target Leverage Ratio is achieved, thereafter reverting to the existing terms of no more than LIBOR plus 3.25%;
a minimum Consolidated EBITDA (as defined in our Credit Facility) of $9.0 million for the second quarter of 2013, with no maximum Consolidated Total Leverage Ratio covenant for such period;
an increase in the allowed Maximum Adjusted Consolidated Total Leverage Ratio to 7.25 to 1.0 starting with the quarter ended September 30, 2013, declining each quarter thereafter until reaching 4.50 to 1.0 in the first quarter of 2015;
the minimum consolidated interest coverage ratio was changed to 2.25 to 1.00 for the periods ending September 30, 2013 and December 31, 2013 and 2.50 to 1.00 for the periods ending March 31, 2014 and thereafter;
until the Target Leverage Ratio is achieved, a limit to our growth capital expenditures of $25.0 million for the remainder of 2013 and $25.0 million for the 18 months ended June 30, 2015; provided that if additional cash, as required under the Second Amendment, is placed in the Collateral Account, such expenditures may be increased to $28.0 million each period;
until the Target Leverage Ratio is achieved, distributions to our unitholders are effectively limited to our established minimum quarterly distribution of not more than $0.40 per unit;
a required infusion of $40.0 million into the Partnership from the Collateral Account ($34.2 million plus $5.8 million of distributions attributable to the quarter ending March 31, 2013) by Southcross Energy LLC and/or our General Partner during the second quarter of 2013 in exchange for new equity securities, which are required to be non-cash pay until the Target Leverage Test has been satisfied; and