10-K 1 a201510-kdoc.htm 10-K 10-K
 
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, 2015
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.)
1717 Main Street, Suite 5200
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, 2015 was approximately $240,817,530 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 April 8, 2016, the registrant has 28,512,465 common units, 12,213,713 subordinated units and 15,958,990 Class B Convertible Units outstanding. The registrant's common units trade on the New York Stock Exchange under the symbol "SXE".
DOCUMENTS INCORPORATED BY REFERENCE
None





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
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, 2015

PART I
Item 1.
Business
Item 1A.
Risk Factors
Item 1B.
Unresolved Staff Comments
Item 2.
Properties
Item 3.
Legal Proceedings
Item 4.
Mine Safety Disclosures
PART II
Item 5.
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities
Item 6.
Selected Financial Data
Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
Item 8.
Financial Statements and Supplementary Data
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A.
Controls and Procedures
Item 9B.
Other Information
PART III
Item 10.
Directors, Executive Officers and Corporate Governance
Item 11.
Executive Compensation
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13.
Certain Relationships and Related Transactions, and Director Independence
Item 14.
Principal Accountant Fees and Services
PART IV
Item 15.
Exhibits and Financial Schedules
 
Signatures


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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 the price and demand of products derived from these commodities, particularly in the depressed energy price environment that began in the second half of 2014, which has the potential for further deterioration and may result in a continued reduction in exploration, development and production of crude oil and natural gas;
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 taken or inactions or nonperformance by third parties, including suppliers, contractors, operators, processors, transporters and customers;
the financial condition and creditworthiness of our customers;
our ability to recover NGLs effectively 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, including with respect to our acquisition of certain gathering and processing assets from TexStar Midstream Services, LP in August 2014 and other assets acquired in May 2015;
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 financial covenants, and the potential for lack of access to debt and equity capital markets as a result of the depressed energy price environment;
our ability to generate sufficient operating cash flow to resume funding our quarterly distributions;
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, fractionation and treating 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;
the impact on our financial condition and operations resulting from the financial condition and operations of our controlling unitholder, Southcross Holdings LP;
changes in general economic conditions;
other financial, operational and legal risks and uncertainties detailed from time to time in our filings with the U.S. Securities and Exchange Commission; and
the financial health of our controlling unitholder, Southcross Holdings LP, and its ability to pay amounts owed to us on a timely basis.

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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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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 Holdings LP, a Delaware limited partnership (“Holdings”), indirectly owns 100% of Southcross Energy Partners GP, LLC, a Delaware limited liability company and our general partner (“General Partner”) (and therefore controls us), all of our subordinated units, all of our Class B Convertible units (the "Class B Convertible Units") and a portion of our common units. Our General Partner owns an approximate 2.0% interest in us and all of our incentive distribution rights. Following the emergence of Holdings from its Chapter 11 reorganization proceeding on April 13, 2016 (as discussed below under “Recent Developments - Chapter 11 Reorganization”), EIG Global Energy Partners, LLC (“EIG”) and Tailwater Capital LLC (“Tailwater”) (collectively, the “Sponsors”) each indirectly own approximately one-third of Holdings, and a group of consolidated lenders under Holdings' revolving credit facility and term loan own the remaining one-third equity interest, which was previously owned by Charlesbank Capital Partners, LLC.
We are a master limited partnership, headquartered in Dallas, Texas, 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 four gas processing plants, two fractionation facilities and approximately 3,138 miles of pipeline.
Recent Developments
Holdings Chapter 11 Reorganization

On March 28, 2016, Holdings and certain of its subsidiaries (other than us, our General Partner and our subsidiaries) filed a pre-packaged plan of reorganization (the “POR”) under Chapter 11 of the U.S. Bankruptcy Code in the Southern District of Texas to restructure its debt obligations and strengthen its balance sheet. Our operations, customers, suppliers, partners and other constituents were excluded from such proceeding. On April 11, 2016, the bankruptcy court confirmed Holdings’ POR, and on April 13, 2016, Holdings and its subsidiaries emerged from its bankruptcy and consummated the following principal transactions:

issued 33.34% of the limited partner interests of Holdings to the lenders under Holdings’ credit facility in exchange for the elimination of certain funded debt obligations;

issued 33.33% of the limited partner interests of Holdings to EIG in exchange for approximately $85 million in cash;

issued 33.33% of the limited partner interests of Holdings to Tailwater in exchange for approximately $85 million in cash;

committed to provide us $50 million (as part of the Equity Cure Agreement discussed below), from the $170 million in new equity contributed to Holdings from the Sponsors, to ensure we have sufficient liquidity to comply with the applicable financial covenants set forth in our credit agreement; and

paid all of the receivable due to us.

In addition, pursuant to the terms of the POR, the Lenders have the right to appoint two members (one of which must be independent) to the board of directors of our general partner due to their equity interest in Holdings. The directors appointed by the Lenders will replace the directors previously appointed by Charlesbank Capital Partners, LLC. The court authorized

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Holdings to continue to pay all of its trade creditors, suppliers and contractors, including us, in the ordinary course of business and any amounts owed by Holdings to these parties will not be impacted by the bankruptcy proceeding. We believe Holdings’ reorganization and POR will enhance our liquidity position, strengthen our balance sheet and position it to continue to support our business and growth.

Holdings Drop-Down Acquisition

On May 7, 2015, we acquired gathering, treating, compression and transportation assets (the “2015 Holdings Acquisition”) pursuant to a Purchase, Sale and Contribution Agreement among Holdings, TexStar Midstream Utility, LP, Frio LaSalle Pipeline, LP (“Frio”), us and certain of our subsidiaries. The acquired assets consist of the Valley Wells sour gas gathering and treating system (the “Valley Wells System”), compression assets that are part of the Valley Wells and Lancaster gathering and treating systems (the “Compression Assets”) and two NGL pipelines. Due to the common control aspects in the 2015 Holdings Acquisition, the Partnership’s financial results retrospectively include the financial results for the Valley Wells System and the Compression Assets for all periods ending after August 4, 2014, the date that Southcross Energy LLC and TexStar Midstream Services, LP, a Texas limited partnership (“TexStar”), combined pursuant to a contribution agreement in which Holdings was formed (the “Holdings Transaction”). For additional details regarding the 2015 Holdings Acquisition, see Notes 1 and 3 to our consolidated financial statements.

Liquidity Consideration
As of December 31, 2015, we were not in compliance with the consolidated total leverage ratio of our Financial Covenants (as defined in Note 8 to our consolidated financial statements) absent an equity cure of $14.9 million. We used the remaining $3.0 million of the contractual $13.0 million non-cash equity cure credit amount from our Credit Agreement Amendment (defined in Note 8 to our consolidated financial statements) to fund a portion of our equity cure. On March 17, 2016, we entered into an equity cure contribution agreement (the “Equity Cure Agreement”) with Holdings whereby we have the right to cure any default with respect to our Financial Covenants by having Holdings purchase equity interests in or make capital contributions to us, in an aggregate amount of up to $50 million. On March 30, 2016, we received $11.9 million from Holdings, pursuant to the terms of the Equity Cure Agreement, to fund the remaining balance of the equity cure required to comply with the consolidated total leverage ratio of our Financial Covenants. In addition, in developing our annual budget for 2016, our forecast indicates future shortfalls in the amount of consolidated EBITDA necessary to remain in compliance with the consolidated total leverage ratio of our Financial Covenants in our Credit Facility for the remainder of 2016. We will have the remaining $38.1 million from the Equity Cure Agreement available to fund additional equity cures through the fourth quarter of 2016, as needed, and to assist in the Partnership's ability to continue as a going concern for a reasonable period of time. We believe that this amount will be sufficient to fund any equity cure requirements during this period. For additional details regarding this equity cure, see Notes 1 and 2 to our consolidated financial statements.
Distribution Suspension
In January 2016 and effective for the fourth quarter of 2015, the board of directors of our General Partner voted not to pay a quarterly distribution and instead to reserve any excess cash for the operation of our business. Quarterly distributions were paid by the Partnership through the third quarter of 2015. The board of directors of our General Partner and our management believe this suspension to be in the best interest of our unitholders. The board of directors and management will continue to evaluate the Partnership's ability to reinstate the distribution in future periods. See Notes 1, 2 and 5 to our consolidated financial statements.
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:
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

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reduced disclosure about the emerging growth company's executive compensation arrangements pursuant to the rules applicable to smaller reporting companies.
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.
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.
Ownership Structure
The following table depicts our ownership structure as of December 31, 2015:
Description
Percentage
ownership
Ownership by non-affiliates:
 
Public common units
37.8
%
Southcross Holdings LP's ownership:
 
Common units
11.5
%
Subordinated units
21.1
%
Class B Convertible Units
27.6
%
General partner interest
2.0
%
Total
100.0
%
Business Strategy
Our principal business objective is to focus on profitability and improving our business operations by expanding the capacity and efficiency of our assets by making selective acquisitions and by managing costs 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 the Eagle Ford Shale region. 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.
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 of and jointly with our Sponsors.
Execute accretive drop-downs of complementary assets from Holdings. We intend to pursue accretive acquisitions from our parent company, Holdings, which strategically expand or complement our existing asset portfolio, primarily in the Eagle Ford Shale region. However, Holdings is not obligated to execute these drop-downs.

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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 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. 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, including reduction of leverage on the consolidated balance sheet, which we believe will serve the long-term interests of our unitholders.
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 region in South Texas, which is one of the most resource rich drilling regions in the U.S. We also operate in Mississippi and Alabama. We believe the 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 region has allowed us to execute several organic capital projects in the area, to identify additional infrastructure needs adjacent to our existing systems and to make strategic acquisitions in that area, including our acquisition of the TexStar Rich Gas System. Our growth opportunities are impacted primarily by natural gas production in our Eagle Ford Shale region. Our Eagle Ford Southcross pipeline catchment area includes multiple prospective production zones, including the Olmos tight sands formation, which overlays the Eagle Ford Shale. Our business activity provides us with relationships 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 area.
Mississippi and Alabama.  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 South Texas 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. 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 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 Sponsors with significant industry expertise.  Our Sponsors are the principal owners of Holdings, the owner of our General Partner and the holder of an approximate 61.5% limited partnership interest in us, and have substantial experience as private equity investors in the energy and midstream sectors. Our Sponsors' investment professionals have deep experience in identifying, evaluating, negotiating and financing acquisitions and investments

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in the midstream sector. We believe that our Sponsors provide us with strategic guidance, financial expertise and 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, four natural gas processing plants, two fractionation facilities, 11 compressor stations, a treating system, and pipelines. 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, 2015:
 
As of December 31, 2015
 
Year Ended December 31, 2015
Gathering systems and intrastate pipelines
Miles
 
Average throughput volumes of natural gas (MMcf/d)
South Texas
2,028

 
662

Mississippi/Alabama
1,110

 
214

Total
3,138

 
876

 
As of December 31, 2015
 
Year Ended December 31, 2015
Processing plants
Approximate design of gas processing capacity (MMcf/d)
 
Average volume of processed gas (MMcf/d)
Gregory
135

 
50

Conroe
50

 
27

Woodsboro
200

 
164

Lone Star
300

 
181

Total
685

 
422

 
As of December 31, 2015
 
Year Ended December 31, 2015
Fractionation plants
Approximate design of fractionation capacity (Bbls/d)
 
Average volume of NGLs sold from output (Bbls/d)
Gregory
4,800

 

Bonnie View
22,500

 
13,312

Total
27,300

 
13,312

 
As of December 31, 2015
Field Compression Stations
Approximate design of compression horsepower
Barracuda
2,760

Comet
5,520

Corvair
2,760

Cyclone
2,760

El Dorado
8,280

Lancaster Plant
5,700

Oppenheimer
1,160

Scott North
637

Skylark
1,340

Urban
500

Valley Wells Treater
21,305

Total
52,722


As a result of the TexStar Rich Gas System Transaction, we acquired equity interests in three joint ventures, including T2 Eagle Ford Gathering Company LLC (“T2 Eagle Ford”), T2 LaSalle Gathering Company LLC (“T2 LaSalle”) and T2 EF Cogeneration Holdings LLC (“T2 Cogen”), which operate pipelines and a cogeneration facility located in South Texas. We indirectly own a 50% interest in T2 Eagle Ford, a 50% interest in T2 Cogen and a 25% interest in T2 LaSalle. T2 Cogen

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operates two gas powered turbines that buy fuel from related parties and charges such parties based on monthly electrical activity. The following table provides information regarding our pipeline joint venture investments, T2 Eagle Ford and T2 LaSalle, for the year ended December 31, 2015:
 
As of December 31, 2015
Joint venture pipelines
Miles
 
Leased Capacity
 
Average throughput volumes of natural gas (MMcf/d)(1)
Dimmit
46

 
50
%
 
64.3

LaSalle
58

 
25
%
 
117.1

Choke Canyon
72

 
50
%
 
173.1

Residue Header
57

 
50
%
 
134.8

Total
233

 
 
 
 

(1) Average throughput volumes of natural gas calculated for the entire year ended December 31, 2015.
We derive revenue primarily from fixed-fee and fixed-spread arrangements. For the year ended December 31, 2015, our fixed-fee and fixed-spread arrangements accounted for approximately 87% 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 and compression assets.
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 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 typically at its highest during the six-month peak heating season of October through March. Demand for 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

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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 Webb and Dimmitt Counties near the Texas-Mexico border. As of December 31, 2015, these assets consisted of approximately 2,028 miles of pipeline ranging in diameter from 2 to 24 inches, our Woodsboro processing plant, our Bonnie View NGL fractionation facility, our Gregory processing plant and NGL fractionation facility, our Lone Star processing plant, our Conroe gathering system and its associated processing plant, our Valley Wells System and 11 compression stations.
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 Lone Star, 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.
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 July 2015, we experienced pressure issues within the depropanizer tower at Bonnie View that resulted in a 50% reduction in operating capacity for the remainder of 2015. In June 2015, we completed the NGL pipelines, which include a Y-grade pipeline that connects our Woodsboro processing facility to Holdings' Robstown fractionator ("Robstown") and a propane pipeline from our Bonnie View fractionator to Robstown. The installation of the NGL pipelines resulted in our ability to sell incremental Y-grade to Holdings and mitigated the financial impact of the reduced capacity at Bonnie View.
Our Lone Star processing plant is a 300 MMcf/d cryogenic processing plant located in Bee County, Texas, and was acquired from TexStar in August 2014. The plant is interconnected with other South Texas rich gas supply basins via our Bee Line pipeline which was placed into service in 2013.
Our Gregory processing plant is a cryogenic processing plant comprised of two units collectively having a total capacity of 135 MMcf/d, and a fractionator having total capacity of 4,800 BBls/d. This plant processes natural gas from both a local gathering system and from sources elsewhere on our South Texas pipeline systems. The fractionator is currently idle due to excess fractionation capacity on our system. NGLs produced at our Gregory processing plant are typically fractionated at our Bonnie View fractionator or shipped to Robstown.
On January 20, 2015, our Gregory processing plant experienced a fire which caused damage to one of our two processing plants, taking all 135 MMcf/d of processing capacity temporarily out of service. In February 2015, we brought 55 MMcf/d back on-line. The remaining 80 MMcf/d of processing capacity will remain off-line until such time it is deemed necessary that the remaining processing capacity is needed. We reached our insurance deductible as part of efforts to return the facility to service from the fire and recorded a receivable of $0.5 million in our consolidated balance sheets as of December 31, 2015 for amounts incurred above the deductible.
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 and process natural gas. We have a mixture of fixed-fee and percent of proceeds 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.
Our Valley Wells System, located in LaSalle County, Texas, has sour gas treating capacity of approximately 100 MMcf/d and is supported by a 60 MMcf/d minimum volume commitment from Holdings for gathering and treating services, while Holdings has producer contracts with minimum volume commitments totaling 35 MMcf/d behind the system. The system is connected to our rich gas system for transport and processing.
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 approximately 618 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 and Texas Eastern Company—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 492 miles of natural gas gathering and transmission pipelines 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. The system receives natural gas from unaffiliated interstate pipelines and services markets along the system.
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 Inc., Spectra Energy Partners, LP and Targa Pipeline Partners, L.P.
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.
Our top ten customers accounted for 54.2% of our revenue for the year ended December 31, 2015. Due to the continued volatility of commodity prices, some of our customers may experience material financial and liquidity issues. No significant nonpayment from customers has occurred as of December 31, 2015, however, we are aware of certain customers that have begun to undergo financial restructurings in 2016. We continue to monitor the proceedings of these customers' situations and will record an allowance for uncollectible accounts receivable at which time it may become necessary.
Governmental Regulation
We are subject to regulation by the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration ("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. crude oil and natural gas transmission pipelines in "high-consequence areas". 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 (the "2011 Pipeline Safety Act"), reauthorized funding for federal pipeline safety programs, increased penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines.
The 2011 Pipeline Safety Act increased the maximum administrative civil penalties for violation of the pipeline safety laws and regulations after January 3, 2012 to $0.2 million per violation per day, with a maximum of $2.0 million for a series of violations. In October 2015, PHMSA proposed changes to its pipeline safety regulations that would significantly extend the integrity management requirements to previously exempt pipelines and would impose additional obligations on pipeline operators that are already subject to the integrity management requirements. PHMSA’s proposed rule would also require annual reporting of safety-related conditions and incident reports for all gathering lines and gravity lines, including pipelines that are currently exempt from PHMSA regulations. PHMSA issued a separate regulatory proposal in July 2015 that would impose pipeline incident prevention and response measures on pipeline operators. PHMSA also 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

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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; 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; the OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals; the Environmental 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; and the Department of Homeland Security Chemical Facility Anti-Terrorism Standards, which are designed to regulate the security of high-risk chemical facilities. In July 2015, we paid a $0.1 million fine to OSHA related to the fire at our Gregory facility in January 2015. We do not believe that compliance with these regulations will have a material adverse effect on our business, financial position or results of operations or cash flows.
Further, exposure to gas containing certain levels of hydrogen sulfide, referred to as sour gas, can be harmful to humans. Some of the gas processed at our sour gas treating and processing facility, as part of the Valley Wells System, contains high levels of hydrogen sulfide. We do not believe that compliance with the applicable federal and state environmental, health and safety laws will have a material adverse effect on our business, financial position or results of operations or cash flows.
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., TexStar Transmission, LP, Southcross Nueces Pipelines LLC 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 ("FERC") jurisdiction under Section 311 of the Natural Gas Policy Act ("NGPA"), and Part 284 of FERC's regulations. Pipelines providing certain 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

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by FERC are maximum rates and we may negotiate at or below such rates depending on the market. Currently, FERC reviews our rates every five years and such rates may increase or decrease as a result of such reviews. During the year ended December 31, 2015 FERC approved tariff rates for three of our systems. The next rate review occurs in 2017. The terms and conditions of service set forth in the intrastate pipeline's statement of operating conditions are also subject to FERC's review and approval. In the future, should FERC determine not to authorize rates which fully recover our costs of service, 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 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 the jurisdiction of FERC under the Natural Gas Act ("NGA"). Specifically, Section 1(c) of the NGA exempts from 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, 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 FERC's regulations.
Gathering Pipeline Regulation
Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC. Although FERC has not made a formal determination with respect to all of our facilities we believe to be gathering facilities, we believe that our natural gas gathering pipelines meet the traditional tests that 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 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 FERC, the courts or Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, 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 FERC and, furthermore, provides FERC with additional civil penalty authority. On January 19, 2006, 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,

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directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC or the purchase or sale of transportation services subject to the jurisdiction of 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 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, 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 (the "CFTC") is directed under the Commodities Exchange Act (the "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 authority to seek civil penalties of up to the greater of $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 FERC to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce. In 2007, 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, 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 FERC's jurisdiction, to provide by May 1 of each year an annual report to 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 FERC's policy statement on price reporting. In June 2010, FERC issued the last of its three orders on rehearing and clarification further clarifying its requirements.
In May 2010, 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 FERC's website, and that such quarterly reports may not contain information redacted as privileged. 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 FERC to monitor actual transactions for evidence of market power or undue discrimination. Order No. 735 also extends 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.
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., Southcross Nueces Pipelines LLC, FL Rich Gas Utility and TexStar Transmission, LP are required to file gas tariffs and Southcross NGL Pipeline Ltd. has filed NGL tariffs 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 negotiated contracts. 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. This requirement includes our Southcross Alabama Pipeline LLC ("SAP LLC") which now includes the assets of Southcross Alabama Gathering System, L.P. which was merged with and into SAP LLC on December 1, 2014.

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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
The transportation of natural gas in interstate commerce has been regulated by FERC under the NGA, the NGPA and regulations issued under those statutes and the transportation of NGLs in interstate commerce has been regulated by FERC under the Interstate Commerce Act. Historically the price, terms and conditions of the sale of natural gas at wholesale in interstate commerce was regulated by FERC, but the sale of NGLs was not regulated. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.
The price at which we sell natural gas is currently not subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by 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. While sales by producers of natural gas and sales of NGLs can currently be made at market prices, 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. 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. In addition, in August 2014, DHS issued an advanced notice of proposed rulemaking designed to identify ways to make the Chemical Facility Anti-Terrorism Standards program more effective. 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, record-keeping 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 DHS, 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;

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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.
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 provide assurance, 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.
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

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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, 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.
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 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.
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. The scope of applicability for most of our engines is the requirement to follow a prescribed maintenance plan or comply with already existing New Source Performance Standard JJJJ. The few engines we do have that are subject to the control and compliance provisions of National Emission Standards for Hazardous Air Pollutants Standard ZZZZ are new engines which meet the emissions limitations therein. We do not believe that compliance with these rules will have a material adverse effect on our operations.
On April 17, 2012, the EPA approved final rules that establish new air emission controls for oil and natural gas production and natural gas processing operations. This 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. On August 18, 2015, the EPA proposed additional regulations to control emissions of methane and VOCs from various oil and natural gas operations. 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

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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 business, financial condition, results of operations or cash flow.
Endangered Species
The Endangered Species Act (the "ESA") restricts activities that may affect endangered or threatened species or their habitats. The current listing of species as threatened or endangered has not had a material adverse effect on our business, financial condition, results of operations or cash flow. 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.
Climate Change
The EPA has adopted regulations under existing provisions of the CAA that require certain large stationary sources to obtain Prevention of Significant Deterioration ("PSD") pre-construction permits and Title V operating permits for GHG emissions which does not currently apply to our facilities. In addition, in September 2009, the EPA issued a final rule requiring the monitoring and reporting of greenhouse gas emissions from certain large greenhouse gas emissions sources. Our Gregory, Woodsboro, Bonnie View, Conroe, Lone Star and El Dorado facilities are or will be required to report under this rule. This reporting rule was expanded in November 2010 to include petroleum and natural gas facilities, including certain natural gas transmission compression facilities, and again in October 2015 to include onshore petroleum and natural gas gathering and boosting activities and natural gas transmission pipelines. We have submitted the reports required under the reporting rule on a timely basis and have adopted procedures for future required reporting.
While Congress has from time to time considered legislation to reduce emissions of GHGs, the prospect for adoption of significant legislation at the federal level to reduce GHG emissions is perceived to be low at this time. Nevertheless, the Obama administration has announced it intends to adopt additional regulations to reduce emissions of GHGs and to encourage greater use of low carbon technologies. Several states have also implemented programs to reduce and/or monitor GHG emissions. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that limit emissions of GHGs could adversely affect demand for the oil and natural gas that exploration and production operators produce, including our current or future customers, which could thereby reduce demand for our midstream services.
In addition, in December 2015, over 190 countries, including the United States, reached an agreement to reduce greenhouse gas emissions. We continue to monitor the international efforts to address climate change. To the extent the United States and other countries implement this agreement or impose other climate change regulations on the oil and gas industry, it could have an adverse direct or indirect effect on our business.
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 GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.
Finally, increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. 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.

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Employees
Currently, we do not have any employees. We rely solely on officers and employees of our General Partner to operate and manage our business. Our General Partner employed 291 employees as of December 31, 2015. None of these employees are covered by collective bargaining agreements, and our General Partner considers its employee relations to be good.
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, as our current "Lead Director," 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 1717 Main Street, Suite 5200, Dallas, Texas 75201.
Lead Director
In accordance with the Corporate Governance Guidelines adopted by our General Partner, Jerry W. Pinkerton is our “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
We make available free of charge, within the "Investors" section of our website at www.southcrossenergy.com, and in print to any unitholder who so requests, our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Audit Committee Charter and Compensation Committee Charter. Requests for print copies may be directed to investorrelations@southcrossenergy.com or to: Investor Relations, Southcross Energy Partners, L.P., 1717 Main Street, Suite 5200, Dallas, Texas 75201, or telephone (214) 979-3720. We will post on our website all waivers to or amendments of the Code of Business Conduct and Ethics, that are required to be disclosed by applicable law and the NYSE's Corporate Governance Listing Standards. The information contained on, or connected to, our website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.


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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. The following risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we deem to be immaterial also may materially adversely affect our business, results of operations and financial condition and our ability to make distributions.
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 cash from operations, following the establishment of cash reserve and payment of fees and expenses, including cost reimbursements to our General Partner, each quarter to enable us to pay the minimum quarterly distribution. For example, in January 2016 and effective for the fourth quarter of 2015, the board of directors of our General Partner voted to not pay a quarterly distribution and to instead reserve any excess cash for the operation of our business. Our decision to reserve all of our cash on hand for allowed purposes and not distribute it may significantly impact our unitholders, as well as our business and operations. The market value of our units may remain depressed or decline further unless and until we resume a distribution. In addition, refinancing or restructuring of our debt may require us to accept covenants that may restrict our ability to reinstate distributions. External perceptions of the health of our business and our liquidity also may be impacted, which could limit further our ability to access capital markets, cause our vendors to tighten our credit terms and cause a strain in our relationship with customers and other business partners. 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, crude oil, natural gas and NGLs and the market prices of crude 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, whether caused by mechanical failure resulting from maintenance, construction or otherwise;
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, general and administrative costs;
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; and
the financial health of our parent company and its ability to pay amounts owed to us on a timely basis.

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In addition, the actual amount of cash we will have available for distributions will depend on other factors, some of which are beyond our control, including:
the level of capital expenditures we make;
the cost of acquisitions, if any;
our debt service requirements and other liabilities;
fluctuations in our working capital needs;
our ability to borrow funds and access capital markets;
restrictions contained in our debt agreements;
the amount of cash reserves established by our General Partner; and
other business risks affecting our cash levels.
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 crude oil, natural gas and NGL prices;
demand for crude 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 crude oil and natural gas reserves. Drilling and production activity generally decreases as natural gas, crude oil or NGL prices decrease. Declines in natural gas, crude 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.    
Natural gas, crude oil and NGL prices declined significantly in the second half of 2014 and have been negatively affected by a combination of factors, including weakening demand, increased production, the decision by the Organization of Petroleum Exporting Countries to keep production levels unchanged and a strengthening in the U.S. dollar relative to most other currencies. Given the historical volatility of crude oil prices, there remains a risk that prices could further deteriorate due to increased domestic production, slowing economic growth rates in various global regions and/or the potential for significant supply and demand imbalances.
The decline in natural gas, crude oil and NGL prices has negatively impacted exploration, development and production activity, and the sustained low prices of any of these commodities could lead to a material decrease in such activity. Certain of our producers and other suppliers are tied to crude oil wells, and any sustained reduction in exploration or production activity in

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our areas of operation, whether related to crude oil, natural gas or NGLs, or a combination of them, could lead to reduced utilization of our assets, including the volume of natural gas flowing on our system.
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 by customers and our ability to attract and maintain customers in a limited number of geographic areas.
A significant portion of our assets are located in the Eagle Ford Shale region, and we intend to focus our future capital expenditures largely on developing our business in this area. As a result, our financial condition, results of operations and cash flows are significantly dependent upon the demand for our services in this area. Due to our focus on this area, an adverse development in natural gas production from this area, such as decreased development or production activity, 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 execute effectively on 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 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.
Energy prices are volatile, and a change in these prices in absolute terms, or an adverse change in energy prices, particularly 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 will 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;

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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 crude 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. Extended or future exposure to the volatility of crude oil and natural gas prices could have a material adverse effect on our business, results of operations and financial condition and our ability to make distributions.
In addition, another large portion of our revenues is generated pursuant to fixed-spread contracts under which we strive to buy and sell equal volumes of natural gas and NGLs at prices based upon the same index price of the commodity. Our ability to do this is based upon a number of factors, including willingness of customers to accept the same index as a basis, physical differences in geography, product specifications and ability to market products at the anticipated differential from the pricing index.
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.

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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.
We depend on a relatively limited number of customers.
A significant percentage of our revenue is attributable to a relatively limited number of customers. Our top ten customers accounted for 54.2% of our revenue for the year ended December 31, 2015. We have gathering, processing, 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, many of our customers are oil and gas companies that are facing liquidity constraints in light of the current commodity price environment and may be disproportionately affected by such constraints as compared to larger, better capitalized companies. This concentration of our customers in the energy industry may impact our overall exposure to credit risk as customers may be affected similarly by prolonged changes in economic and industry conditions. If a significant number of our customers experience a prolonged business decline or disruptions or enter into bankruptcy, we will incur increased exposure to credit risk and bad debts. Any material nonpayment or nonperformance by any of our key customers could have a material adverse effect on our revenue, gross operating margin, cash flows and our ability to make cash distributions to our unitholders. In any of these situations, our revenue, gross operating margin, cash flows and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to concentrated risk of nonpayment or nonperformance 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, process or transport do not meet the natural gas and NGL quality requirements of such pipelines or facilities, our gross operating margin, 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 and treating 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, process, treat or transport do not meet the natural gas quality requirements (such as hydrocarbon dew point, temperature and foreign content including water, sulfur, carbon dioxide and hydrogen sulfide) of such pipelines or facilities, our gross operating margin, cash flow and our ability to make cash distributions to our unitholders could be adversely affected.

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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, including any interruption of our operations as a result of such accident or event, 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, including gas with high levels of hydrogen sulfide, and other hydrocarbons or losses of natural gas as a result of human error, the malfunction of equipment or facilities, which can result in personal injury and loss of life, pollution, damage to equipment and suspension of operations;
ruptures, fires and explosions; and
other hazards, including those associated with high-sulfur content, or sour gas, 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 loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. These risks may also result in interruptions, 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 Holdings or 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 Holdings or 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 revolving credit facility restricts us from making acquisitions,

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(iii) outbid by competitors or (iv) 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 their limited history with our assets;
coordinating geographically disparate organizations, systems and facilities;
the assumption of unknown liabilities;
limitations on rights to indemnity from the seller;
mistaken assumptions about the overall costs of equity or debt;
the diversion of management's and employees' attention from other business concerns;
unforeseen difficulties operating in new geographic areas and business lines; and
customer or key employee losses at the acquired businesses.
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.
Our growth strategy requires access to new capital. Tightened capital markets or increased competition for investment opportunities could impair our ability to grow.
We continuously consider and enter into discussions regarding potential acquisitions or growth capital expenditures. Any limitations on our access to new capital will impair our ability to execute this strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire strategic and accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our initial cost of equity include market conditions, including our then current unit price, fees we pay to underwriters and other offering costs, which include amounts we pay for legal and accounting services. The primary factors influencing our cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges we pay to lenders.
Weak economic conditions and the volatility and disruption in the financial markets could increase the cost of raising money in the debt and equity capital markets substantially while diminishing the availability of funds from those markets. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers. These factors may impair our ability to execute our growth strategy.
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 execute fully on 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 and any sustained depression of natural gas, NGL and/or crude oil prices (including further extension of the low energy price environment that began in the second half of 2014), 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

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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, 2015, we had total principal indebtedness of $643.3 million, comprised of $443.3 million related to our term loan and $200.0 million (including outstanding letters of credit) related to our revolving credit facility, which had no remaining borrowing capacity. 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 parent company's and our own future financial and operating performance, which will be affected by prevailing economic conditions, our Sponsor's ability to fund equity cures, as well as financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.
A shortage of skilled labor in the midstream natural gas industry could reduce labor productivity and increase costs, which could have a material adverse effect on our business and results of operations.
The gathering, 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 revolving credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and the 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 revolving 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 revolving 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;

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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 revolving 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 provide assurance that we will meet those ratios and tests. However, on March 17, 2016, we entered into the Equity Cure Agreement with Holdings whereby we have the right to cure any default with respect to a financial covenant in the revolving credit agreement by having Holdings purchase equity interests in or make capital contributions to us, up to an aggregate amount of $50 million. See Note 2 to our consolidated financial statements.
The provisions of our revolving credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our revolving 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 revolving 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 Note 8 to our consolidated financial statements.
If we continue to be unable to generate enough cash flow from operations to service our indebtedness or are unable to use future borrowings to refinance our indebtedness or fund other capital needs, we may have to undertake alternative financing plans, which may have onerous terms or may be unavailable.
We cannot assure you that our business will generate sufficient cash flow from operations to service our outstanding indebtedness, or that future borrowings will be available to us in an amount sufficient to enable us to pay our indebtedness or to fund our other capital needs. If we do not generate sufficient cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:
refinancing or restructuring all or a portion of our debt;
obtaining alternative financing;
selling assets;
reducing or delaying capital investments;
seeking to raise additional capital; or
revising or delaying our strategic plans.
However, we cannot assure you that we would be able to implement alternative financing plans, if necessary, on commercially reasonable terms or at all, or that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations and capital requirements or that these actions would be permitted under the terms of our various debt instruments.
Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing could materially and adversely affect our business, financial condition, results of operations, cash flows and prospects. Any failure to make scheduled payments of interest and principal on our outstanding indebtedness could harm our ability to incur additional indebtedness on acceptable terms. Further, if for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors at that time to declare all outstanding indebtedness to be due and payable (which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements), the lenders under our Senior Credit Facilities, as defined in Note 8 to our consolidated financial statements, could terminate their commitments to loan money, and the lenders could foreclose against our assets

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securing their borrowings and we could be forced into bankruptcy or liquidation. If the amounts outstanding under our Senior Credit Facilities or any of our other indebtedness were to be accelerated, we cannot assure you that the value of our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders.
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 (including, for example, the CAA, the CERCLA, the ESA and the RCRA).
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 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 hazardous wastes and other materials 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.
The EPA has adopted regulations under existing provisions of the CAA that require certain large stationary sources to obtain PSD pre-construction permits and Title V operating permits for GHG emissions, which does not currently apply to our facilities. In addition, in September 2009, the EPA issued a final rule requiring the monitoring and reporting of greenhouse gas emissions from certain large greenhouse gas emissions sources. Our Gregory, Woodsboro, Bonnie View, Conroe, Lone Star and El Dorado facilities are or will be required to report under this rule. This reporting rule was expanded in November 2010 to include petroleum and natural gas facilities, including certain natural gas transmission compression facilities, and again in October 2015 to include onshore petroleum and natural gas gathering and boosting activities and natural gas transmission pipelines. We have submitted the reports required under the reporting rule on a timely basis and have adopted procedures for future required reporting.
While Congress has from time to time considered legislation to reduce emissions of GHGs, the prospect for adoption of significant legislation at the federal level to reduce GHG emissions is perceived to be low at this time. Nevertheless, the Obama administration has announced it intends to adopt additional regulations to reduce emissions of GHGs and to encourage greater use of low carbon technologies. Several states have also implemented programs to reduce and/or monitor GHG emissions. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that limit emissions of GHGs could adversely affect demand for the oil and natural gas that exploration and production operators produce, including our current or future customers, which could thereby reduce demand for our midstream services.
In addition, in December 2015, over 190 countries, including the United States, reached an agreement to reduce greenhouse gas emissions. We continue to monitor the international efforts to address climate change. To the extent the United

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States and other countries implement this agreement or impose other climate change regulations on the oil and gas industry, it could have an adverse direct or indirect effect on our business.
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 GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.

Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. 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.
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, additional private and government studies and increased federal, state and local regulation. For example, from time to time, Congress has considered 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. The EPA has adopted and proposed new regulations under the CAA requiring, among other things, the use of “reduced emission completion” technology for certain hydraulic fracturing operations and related equipment, and has solicited 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. Additional levels of regulation and permits required through the adoption of new laws and regulations at the federal or state level could lead to delays, increased operating costs and prohibitions for producers who drill near our pipelines. This 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.
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 crude 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

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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 in 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, are exempt from the jurisdiction of FERC under the NGA. Although 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 FERC has used to determine if a pipeline is a gathering pipeline and is therefore not subject to 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, 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 FERC on a case-by-case basis. If 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 and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the Natural Gas Policy Act of 1978 (“NGPA”). 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 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 rate established by FERC.
Some of our intrastate pipelines provide interstate transportation service regulated under Section 311 of the NGPA. Rates charged under Section 311 must be “fair and equitable,” and amounts collected in excess of fair and equitable rates are subject to refund with interest. 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. 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 FERC, the courts or Congress.
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, and 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, 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 PHMSA, has adopted regulations requiring pipeline operators to develop integrity management programs for transmission pipelines located where a leak or rupture could harm “high consequence areas” unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. High consequence areas include high population areas, areas that are sources of drinking water, ecological resource areas that are unusually sensitive to environmental damage from a pipeline release and commercially navigable waterways. The regulations require operators, including us, to:

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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 $1.1 million and $0.9 million during the years ended December 31, 2015 and 2014, respectively, 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 2015 and 2014 testing programs.
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 implementation of statutory and regulatory requirements for derivative 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.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") was enacted in 2010 and amended the Commodity Exchange Act. This law regulates derivative and commodity transactions, including crude oil and gas hedging transactions used in our risk management activities. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”) and other regulators to promulgate rules and regulations implementing the new legislation. While many of the 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.
In its rulemaking under the Dodd-Frank Act, the CFTC will likely finalize regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, although certain bona fide hedging transactions would be exempt from these position limits provided that various conditions are satisfied. Once finalized, the position limits rule and its companion rule on aggregation may have an impact on our ability to hedge our exposure to certain enumerated commodities.
The Dodd-Frank Act provisions are also 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. To date, several categories of interest rate and index credit default swaps have been designated by the CFTC as mandatorily clearable swaps. These swaps may also be required to be traded on registered swap execution facilities or exchanges. Both the clearing and the trading requirements are likely to increase significantly 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, we would be required to take certain steps to qualify for the end-user exception. As the CFTC further designates swap contracts as required to be cleared and traded on a trading facility, the utility of the end-user exception will become even more important. Our ability to rely on the end-user exception may change the profitability of our trades or the efficiency of our hedging.
The Dodd-Frank Act and any new regulations could, among other things, significantly increase the cost of entering into derivative and commodity contracts (including from swap record-keeping and reporting requirements), materially alter the terms of derivative contracts, reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, require greater collateral support for derivative contracts and potentially increase our exposure to less creditworthy counterparties.  If we reduce our use of derivatives 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. Any of these consequences could have a material adverse effect on our financial condition, results of operations and cash available for distribution to unitholders.

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Because the CFTC is still in the process of interpreting its regulations, it is possible that some of the derivative and commodity contracts used in our business may be treated differently in the future.  For example, the CFTC may further revise its definitions for spots, forwards, forwards with volumetric optionality, trade options, full requirements contracts and certain other contracts that may combine the elements of physical commodity trades and cash settlement, netting and book-outs.  If these contracts were classified as swaps, the costs of entering into these contracts will likely increase.

Finally, under the Dodd-Frank Act, the CFTC is also directed generally to prevent price manipulation and fraud in physical commodities markets traded in interstate commerce, including physical energy and other commodities, as well as financial instruments, such as futures, options and swaps. Pursuant to the Dodd-Frank Act, the CFTC has adopted additional anti-market manipulation, anti-fraud and disruptive trading practices regulations that prohibit, among other things, fraud and price manipulation in the physical commodities, futures, options and swaps markets.  Accordingly, the CFTC and the self-regulatory organizations (“SROs”), such as commodity futures exchanges, are continuing to develop their respective enforcement authorities and compliance priorities under the Dodd-Frank Act. Given the novelty of the regulations under the Dodd-Frank Act, it is difficult to predict how these new enforcement priorities of the CFTC and the SROs will impact our business. Should we violate the Commodity Exchange Act, as amended, the regulations promulgated by the CFTC, and any rules adopted by the SROs thereunder, we could be subject to CFTC enforcement action and material penalties and sanctions.

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 General Partner's 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 operate our business effectively.
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 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

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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 JOBS Act, our independent registered public accounting firm will not be required to attest formally to the effectiveness of our internal control over financial reporting until 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 Class B Convertible Units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.
Risks Inherent in an Investment in Us
Holdings indirectly 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. Holdings, its general partner and owners, 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.
Holdings controls our General Partner and has the authority to appoint all of the officers and directors of our General Partner. Pursuant to the organizational documents of the general partner of Holdings, two directors (one of whom must be independent) on our board of directors will be appointed by each of EIG, Tailwater and the group of lenders who received membership interests in Holdings in connection with Holdings’ Chapter 11 reorganization. David W. Biegler has been designated as the chairman of the board of our General Partner until August 4, 2016 or until his earlier death or resignation. Although our General Partner has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our General Partner also have a duty to manage our General Partner in a manner that is beneficial to its ultimate owner, Holdings. Conflicts of interest may arise between Holdings and our General Partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our General Partner may favor its own interests and the interests of Holdings over our interests and the interests of our unitholders. These conflicts include the following situations, among others:
Neither our Third Amended and Restated Agreement of Limited Partnership (“Partnership Agreement”) nor any other agreement requires Holdings to pursue a business strategy that favors us.
Our General Partner is allowed to take into account the interests of parties other than us, such as Holdings, in resolving conflicts of interest.
Our Partnership Agreement replaces the fiduciary duties that would otherwise be owed by our General Partner to us and our unitholders with contractual standards governing its duties to us and our unitholders, limits our General Partner’s liabilities, and also restricts the rights of our unitholders with respect to actions that, without the limitations, might constitute breaches of fiduciary duty.
Except in limited circumstances, our General Partner has the power and authority to conduct our business without unitholder approval.
Our General Partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

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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 has limited 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.
The funding of equity cures under the terms of the Equity Cure Agreement.
Each of Tailwater and EIG 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.
Tailwater and EIG are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. Tailwater and EIG may each 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 Tailwater and EIG may offer us the opportunity to buy additional assets from them, none of them are under a contractual obligation to do so and we are unable to predict whether or when such acquisitions might be completed. Tailwater and EIG are each private equity firms with significantly greater resources than us with experience making investments in midstream energy businesses. Tailwater and EIG may each 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, its executive officers, or any of its affiliates, including Tailwater and EIG. 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 21,804,219 publicly traded common units as of December 31, 2015. In addition, Holdings owned 6,616,400 common units, 12,213,713 subordinated units and 15,958,990 Class B Convertible Units as of December 31, 2015. 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

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bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.
The 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 has limited its liability regarding our obligations.
Our General Partner has limited 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.
If we reinstate our distributions, 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, if we reinstate our distributions and 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 revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.
While our Partnership Agreement requires us to distribute all of our available cash, our Partnership Agreement, including provisions requiring us to make cash distributions contained therein, may be amended.
While our Partnership Agreement requires us to distribute all of our available cash, our Partnership Agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our Partnership Agreement generally may not be amended during the subordination period without the approval of a majority 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, 2015, Holdings, the 100% owner of our General Partner, owned, directly or indirectly, 23.3% of the outstanding common units, 100% of our outstanding subordinated units and 100% of our outstanding Class B Convertible Units.

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Reimbursements due to our General Partner and its affiliates for services provided to us or on our behalf reduce cash available for distribution to our common unitholders. The amount and timing of such reimbursements will be determined by our General Partner.
We will reimburse our General Partner and its affiliates, including Holdings, for expenses they incur and payments they make on our behalf. Under our Partnership Agreement, we reimburse our General Partner and its affiliates for certain expenses incurred on our behalf including, among other items, compensation expense for all employees required to manage and operate our business. Our Partnership Agreement provides that our General Partner will determine 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 reduce the amount of available cash to pay cash distributions to our common unitholders.
Holdings' recent Chapter 11 proceeding may adversely affect us.
On March 28, 2016, Holdings and certain of its subsidiaries (other than us, our General Partner and our subsidiaries) filed a pre-packaged plan of reorganization under Chapter 11 of the U.S. Bankruptcy Code in the Southern District of Texas to restructure its debt obligations and strengthen its balance sheet. On April 11, 2016, the bankruptcy court confirmed Holdings’ Chapter 11 reorganization and on April 13, 2016, Holdings and its subsidiaries emerged from its reorganization. Holdings’ Chapter 11 proceeding may affect adversely the way we and our counterparty affiliates are perceived by investors, financial markets, contract counterparties, customers, suppliers and regulatory authorities, which could adversely affect our operations and financial performance. If we fail to attract and retain customers, as well as other contract or trading counterparties as a result of Holdings’ Chapter 11 reorganization, it could adversely affect our financial performance and results of operations.
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

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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 intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
our General Partner will not be in breach of its obligations under the Partnership Agreement (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, although our General Partner is not obligated to seek such approval;
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

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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 Holdings. Furthermore, if the unitholders are dissatisfied with the performance of our General Partner, they will have little ability to remove our General Partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our Partnership Agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
Even if holders of our common units are dissatisfied, they cannot 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 66 2/3% of all outstanding limited partner units voting together as a single class is required to remove our General Partner. As of December 31, 2015, Holdings indirectly owns an approximate 61.5% limited partner interest in us. 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 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 Holdings to transfer all or a portion of its ownership interest in our General Partner to a third party. The new owner of our General Partner would then be in a position to replace the board of directors and officers of our General Partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers. This effectively permits a “change of control” without the vote or consent of the unitholders.

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We may issue additional units without your approval, which would dilute your existing ownership interests. For example, in connection with our debt agreements' required equity cures, our parent made an $11.9 million contribution to us to fund a portion of our fourth quarter 2015 equity cure, in exchange for between 8.0 million and 13.4 million common units, which will dilute the common unitholders.
Our Partnership Agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
our existing unitholders' proportionate ownership interest in us will decrease;
the amount of cash available for distribution on each unit may decrease;
because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding unit may be diminished; and
the market price of the common units may decline.
Holdings may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.
As of December 31, 2015, Holdings held an aggregate of 6,616,400 common units, 12,213,713 subordinated units and 15,958,990 Class B Convertible Units. All of the subordinated units will convert into common units at the end of the subordination period. The Class B Convertible Units will convert into common units when we make a distribution for any quarter to holders of common units equal to or more than $0.44 per common unit, we generated class B distributable cash flow, and paid, the declared distribution on all outstanding units for the two prior quarters, and we forecast paying a distribution equal to or more than $0.44 per outstanding unit from forecasted class B distributable cash flow on all outstanding units for the next two quarters. 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, 2015, Holdings owned approximately 23.3% of our 28,420,619 outstanding common units. At the end of the subordination period and following the conversion of the Class B Convertible Units, assuming no additional issuances of common units (other than upon the conversion of the subordinated units and the Class B Convertible Units), Holdings will own approximately 61.5% of our outstanding 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

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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.
The TexStar Rich Gas System and the Valley Wells System may not be as beneficial to us as we expect.
As a result of our acquisition of the TexStar Rich Gas System and the drop-down acquisition of the Valley Wells System, we are subject to additional risks, in particular the risk we fail to realize the expected profitability, growth or accretion from the transaction. These acquisitions involve additional potential risks, including:

failure to operate the current facilities and assets within operational expectations;

construction cost overruns and delays resulting from numerous factors, many of which may be out of our control;

the temporary diversion of management’s attention from our existing business;

an increase in our interest expense and financial leverage resulting from additional debt incurred to finance the TexStar Rich Gas System, which may offset the expected accretion from such acquisition;

operations regarding the joint venture arrangements;

the ability to add additional rich gas volumes onto our system;

failure or delay of a project owned by a subsidiary of Holdings that is expected to bring additional gas volumes onto the TexStar Rich Gas System;

title issues or liabilities or accidents;

the incurrence of unanticipated liabilities and costs for which indemnification is unavailable or inadequate;

environmental or regulatory compliance matters or liabilities.

If these risks or other unanticipated liabilities were to materialize, the desired benefits of the acquisitions of the TexStar Rich Gas System or the Valley Wells System may not be fully realized, and our future financial performance and results of operations could be negatively impacted.

We may be unable to grow through the acquisitions of current or future assets of Holdings, which could limit our ability to maintain or increase distributions to our unitholders.
Holdings is under no obligation to offer us the opportunity to purchase its current or future assets, and the board of directors of its general partner owes fiduciary duties to its members, and not our unitholders, in making any decision to offer us this opportunity. Likewise, we are not required to purchase any additional assets from Holdings.
The consummation of any such purchases will depend upon, among other things, our ability to reach an agreement with Holdings regarding the terms of such purchases (which will require the resolution of the conflict of interest pursuant to our Partnership Agreement) and our ability to finance such purchases on acceptable terms. Additionally, Holdings may be limited in its ability to consummate sales of additional portions of such business to us by the terms of its existing or future credit facilities. Furthermore, our revolving credit facility includes covenants that may limit our ability to finance acquisitions. If a sale by Holdings of any additional assets would be restricted or prohibited by such covenants, we or Holdings may be required to seek waivers of such provisions or refinance those debt instruments in order to consummate a sale, neither of which may be accomplished timely, if at all. If we are unable to grow through additional acquisitions of Holdings’s current or future assets, our ability to maintain or increase distributions to our unitholders may be limited.


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Risks Related to our Common Units
We are not currently in compliance with the New York Stock Exchange’s requirements for continued listing, and therefore may be delisted, which may decrease the common unit price and would have a material adverse effect on our liquidity and our business.
On February 18, 2016, we received a letter from the New York Stock Exchange (“NYSE”) notifying us that we no longer met the NYSE’s requirements for continued listing under Section 802.01C of the NYSE Listed Company Manual because the average closing price of our common units did not equal or exceed $1.00 per unit over a period of 30 consecutive trading days prior to the date of the notification letter. We have six months following receipt of the NYSE’s notice to regain compliance with the minimum unit price criteria. However, if at any time our common unit price drops to the point where the NYSE considers the price to be “abnormally low,” the NYSE has the discretion to begin delisting proceedings immediately. While there is no formal definition of “abnormally low” in the NYSE rules, the NYSE recently has delisted the common stock of issuers when it trades below $0.16 per share. In addition, the NYSE will promptly initiate suspension and delisting procedures if the NYSE determines that we have an average global market capitalization over a consecutive 30 trading-day period of less than $15.0 million.
While we intend to monitor the closing price and average closing price of our common units and consider available options if our common units do not trade at a level likely to result in us regaining compliance with the minimum unit price criteria by August 18, 2016 or within any applicable extension period, no assurances can be made that we will in fact be able to comply and that our common units will remain listed on the NYSE. If our common units are delisted from the NYSE, such delisting could negatively impact the market price of our common units, reduce the number of investors willing to hold or acquire our common units, and limit our ability to issue additional securities or obtain additional financing in the future, and might negatively impact our reputation and, as a consequence, our business.
The price of our common units may be adversely affected by the future issuance and sale of additional common units, including pursuant to the Distribution Agreement, or by our announcement that such issuances and sales may occur.
We cannot predict the size of future issuances or sales of our common units, including those made pursuant to the Distribution Agreement with any of our sales agents or in connection with future acquisitions or capital raising activities, or the effect, if any, that such issuances or sales may have on the market price of our common units. In addition, our sales agents will not engage in any transactions that stabilize the price of our common units. The issuance and sale of substantial amounts of common units, including issuances and sales pursuant to the Distribution Agreement, or announcement that such issuances and sales may occur, could adversely affect the market price of our common units.
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, or if we were otherwise subjected to a material amount of additional 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. We have not requested a ruling from the IRS with respect to our treatment 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 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. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of 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 our cash available for distribution to our unitholders. Therefore, if we were treated as a corporation for federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, 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.

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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.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to 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, members of the U.S. Congress and the President of the United States periodically have considered substantive changes to existing federal income tax laws that would affect the tax treatment of certain publicly traded partnerships, including the elimination of partnership tax treatment for publicly traded partnerships.
Moreover, on May 6, 2015, the IRS and the U.S. Department of the Treasury published proposed regulations (the “Proposed Regulations”) that would affect the qualifying income exception upon which we rely for partnership tax treatment by providing industry-specific guidance regarding whether income earned from certain activities will constitute qualifying income. Although the Proposed Regulations adopt a narrow interpretation of the activities that generate qualifying income, we believe the income that we treat as qualifying income satisfies the requirements for qualifying income under the Proposed Regulations.
Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for us to satisfy the requirements of the exception pursuant to which we are treated as a partnership for federal income tax purposes. 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 any such changes could negatively impact the value of an investment in our common units.
Unitholders’ share of our income is taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.
Because a unitholder is treated as a partner to whom we allocate taxable income that could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income is 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. Recently enacted legislation alters the procedures for assessing and collecting taxes due for taxable years beginning after December 31, 2017, in a manner that could substantially reduce 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 a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our General Partner because the costs will reduce our cash available for distribution. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his or her return. Any audit of a unitholder’s return could result in adjustments not related to our returns, as well as those related to our returns.

Recently enacted legislation applicable to us for taxable years beginning after December 31, 2017 alters the procedures for auditing large partnerships and also alters the procedures for assessing and collecting taxes due (including applicable penalties and interest) as a result of an audit. Unless we are eligible to (and choose to) elect to issue revised Schedules K-1 to our partners with respect to an audited and adjusted return, the IRS may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed under the new rules. If we are required to pay taxes, penalties and interest as a result of audit adjustments, cash available for distribution to our unitholders may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable year.

45


If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be reduced.
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Generally, we expect to elect to have our general partner and our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, but there can be no assurance that such election will be effective in all circumstances. If we are unable to have our general partner and our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be reduced. These rules are not applicable to us for tax years beginning on or prior to December 31, 2017.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If our unitholders sell common units, they will recognize gain or loss 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.
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.
Investments in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, is unrelated business taxable income and is taxable to them. Distributions to non-U.S. persons are reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons are required to file federal income tax returns and pay tax on their share of our taxable income.
We 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 business day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge aspects of our proration method, and, if successful, we would be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
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 business day of each month, instead of on the basis of the date a particular unit is transferred. The U.S. Department of Treasury and the IRS recently issued Treasury regulations that permit publicly traded partnerships to use a monthly simplifying convention that is similar to ours, but they do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to successfully challenge this method, we could be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

46


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.
We have adopted certain valuation methodologies in determining a unitholder's allocation of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of the common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, in certain circumstances, including when we issue additional units, we must determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.
A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in the unitholder's 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 federal income tax purposes. If treated as a new partnership, we must make new tax elections, including a new election under Internal Revenue Code Section 754, and we 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 be 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 are likely to 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.


47


Compliance with and changes in tax laws could adversely affect our performance.
We are subject to extensive tax laws and regulations, including federal and state income taxes and transactional taxes such as sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.

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
Formosa Litigation

On March 5, 2013, one of our subsidiaries, Southcross Marketing Company Ltd., filed suit in a District Court of Dallas County against Formosa Hydrocarbons Company, Inc. (“Formosa”). The lawsuit sought 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 subsidiary 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.  After a bench trial held in January 2015, on February 5, 2015, the judge ruled that Formosa breached certain of its obligations under the gas processing and sales contract and that our subsidiary breached an obligation under each of the gas processing and sales contract and the related residue gas agreement.  The amount of damages awarded to our subsidiary was in excess of the damages awarded to Formosa. Rather than wait for the judge to award attorneys’ fees for each party as to the claims on which it prevailed, the parties have reached an agreement as to the appropriate award of attorneys’ fees. The amount of attorneys’ fees to be paid to our subsidiary is in excess of the attorneys’ fees to be paid to Formosa. After the ruling, our subsidiary filed a motion for reconsideration regarding a claim that was dismissed before trial through summary judgment. Formosa filed its own motion for reconsideration regarding the amount of damages awarded to our subsidiary on one of its claims. A hearing on both motions for reconsideration was held on June 5, 2015. The judge has yet to issue a ruling on these motions. Even if Formosa is successful in its request to reduce the damages awarded to our subsidiary, the amount of damages awarded to our subsidiary would still be in excess of the damages awarded to Formosa. No judgment will be entered until the judge has made a ruling on these motions. Regardless of how the judge rules on these motions, the judgment is not expected to have a material impact on our results of operations, cash flows or financial condition.

Other Proceedings

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. For example, during periods when we are expanding our operations through the development of new pipelines or the construction of new plants, we may become involved in disputes with landowners that are in close proximity to

48


our activities. While we are currently involved in several such proceedings and disputes, our management believes that none of such proceedings or disputes 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.

Item 4.
Mine Safety Disclosures
Not applicable.


49


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 January 1, 2013. Distributions are recorded when paid.
 
Unit Prices
 
Distributions
per common unit
 
 
 
 
 
High
 
Low
 
 
Record date
 
Payment date
Quarter Ended December 31, 2015
$
6.60

 
$
2.28

 
(a)
 
(a)
 
(a)
Quarter Ended September 30, 2015
12.81

 
4.77

 
0.40

 
November 9, 2015
 
November 13, 2015
Quarter Ended June 30, 2015
16.20

 
10.88

 
0.40

 
August 10, 2015
 
August 14, 2015
Quarter Ended March 31, 2015
16.35

 
11.76

 
0.40

 
May 8, 2015
 
May 14, 2015
Quarter Ended December 31, 2014
22.17

 
11.22

 
0.40

 
February 9, 2015
 
February 13, 2015
Quarter Ended September 30, 2014
24.88

 
21.11

 
0.40

 
November 5, 2014
 
November 14, 2014
Quarter Ended June 30, 2014
23.50

 
16.51

 
0.40

 
August 8, 2014
 
August 15, 2014
Quarter Ended March 31, 2014
19.29

 
14.92

 
0.40

 
May 9, 2014
 
May 15, 2014
_______________________________________________________________________________
(a) We did not pay quarterly distributions with respect to the fourth quarter of 2015.
The last reported sale price of our common units on the NYSE on April 8, 2016 was $1.26 and, as of such date, there were approximately 6,925 holders of record of our common units and 28,512,465 common units outstanding. As of April 8, 2016, we have issued 12,213,713 subordinated units, 15,958,990 Class B Convertible Units and 1,156,840 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, as determined by our General Partner.
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 that 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, until the third quarter of 2014, to the holders of our subordinated units of $0.40 per unit, or $1.60 on an annualized basis (with the first such distribution being prorated). There is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our General Partner, taking into consideration the terms of our Partnership Agreement and requirements under our Credit Facility (as defined below). Beginning with the third quarter of 2014, until such time that we have a ratio of distributable cash flow divided by cash

50


distributions (“Distributable Cash Flow Ratio”) of at least 1.0, Holdings, the indirect holder of our subordinated units, has waived the right to receive distributions on any subordinated units that would cause the Distributable Cash Flow Ratio to be less than 1.0. In addition, the Credit Agreement Amendment (defined in Note 8 to the consolidated financial statements) imposed additional restrictions on our ability to declare and pay quarterly cash distributions with respect to our subordinated units.
Distribution Suspension
In January 2016 and effective for the fourth quarter of 2015, the board of directors of our General Partner voted not to pay a quarterly distribution and instead to reserve any excess cash for the operation of our business. Quarterly distributions were paid by the Partnership through the third quarter of 2015. The board of directors of our General Partner and our management believe this suspension to be in the best interest of our unitholders. The board of directors and management will continue to evaluate the Partnership's ability to reinstate the distribution in future periods. See Notes 1, 2 and 5 to our consolidated financial statements.
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
%








51


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 Total Return Index for the period from our IPO (November 7, 2012) to December 31, 2015, assuming an initial investment of $100.
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.”



52


Item 6.
Selected Financial Data
The information in this section should be read in conjunction with Part II, Item 7 and Item 8 of this report. 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 unit and per unit data, and volume data).
 
Year Ended December 31,
 
2015(1)(2)
 
2014(1)(2)
 
2013(1)
 
2012(1)
 
2011(1)
Statements of operations data:
 
 
 
 
 
 
 
 
 
Revenues
$
698,473

 
$
848,513

 
$
634,722

 
$
496,129

 
$
523,149

(Loss) income from operations
(9,536
)
 
(13,228
)
 
(2,995
)
 
3,289

 
16,388

Net loss
(55,493
)
 
(37,731
)
 
(15,970
)
 
(4,488
)
 

Net loss attributable to partners
(51,399
)
 
(36,659
)
 
(17,640
)
 
(4,228
)
 

Net (loss) income from Southcross Energy LLC
 
 
 
 
 
 
(260
)
 
7,539

Basic and diluted earnings per unit:
 
 
 
 
 
 
 
 
 
Net loss allocated to limited partner common units (from November 7, 2012)
(24,790
)
 
(20,175
)
 
(8,683
)
 
(2,072
)
 

Weighted average number of limited partner common units outstanding
26,780,825

 
21,641,635

 
12,224,997

 
12,213,713

 

Loss per common unit
(0.93
)
 
(0.93
)
 
(0.71
)
 
(0.17
)
 

Net loss allocated to Southcross Energy LLC common units

 

 

 
(22,910
)
 
(8,145
)
Weighted average number of Southcross Energy LLC common units outstanding

 

 

 
1,198,429

 
1,197,876

Loss per Southcross Energy LLC common unit(3)

 

 

 
(19.12
)
 
(6.79
)
Performance measures:
 
 
 
 
 
 
 
 
 
Distributions declared per common unit(4)
1.20

 
1.60

 
1.60

 
0.24

 
n/a

Other financial data:
 
 
 
 
 
 
 
 
 
Adjusted EBITDA(5)
83,883

 
51,938

 
34,486

 
24,019

 
28,957

Gross operating margin(5)
181,316

 
127,381

 
93,546

 
71,640

 
62,569

Maintenance capital expenditures
11,618

 
5,777

 
3,353

 
5,193

 
5,317

Growth capital expenditures
90,381

 
162,840

 
90,510

 
164,623

 
150,669

Operating data:
 
 
 
 
 
 
 
 
 
Average volume of processed gas (MMcf/d)
434

 
295

 
219

 
187

 
141

Average volume of NGLs produced (Bbls/d)
43,234

 
23,252

 
14,180

 
3,564

 
2,483

Realized prices on natural gas volumes sold ($/Mcf)
3.16

 
5.28

 
4.13

 
3.12

 
4.46

Realized prices on NGL volumes sold/gal ($/gal)
0.36

 
0.78

 
0.88

 
0.87

 
1.35

Balance sheet data (at period end):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
11,348

 
1,649

 
3,349

 
7,490

 
1,412

Trade accounts receivable
39,585

 
74,086

 
57,669

 
50,994

 
41,234

Accounts receivable - affiliates
49,734

 
11,325

 

 

 

Property, plant, and equipment, net
1,066,001

 
1,058,570

 
575,795

 
550,603

 
369,861

Total assets (6)
1,318,960

 
1,299,712

 
647,078

 
614,220

 
418,230

Total debt (current and long term) (6)
609,018

 
459,027

 
262,063

 
186,615

 
206,125

Capital leases
884

 
1,033

 
908

 

 

Series A 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)
Due to the common control aspects in the 2015 Holdings Acquisition, the 2015 Holdings Acquisition was deemed a transaction between entities under common control and, as such, was accounted for on an “as if pooled” basis for all periods which common control existed (which began on August 4, 2014). The Partnership’s financial results retrospectively include the financial results of the Valley Wells System and the Compression Assets for all periods ending after August 4, 2014, the date of the Holdings Transaction. See Note 3 to our consolidated financial statements for further details. We calculate historical earnings per unit with retrospective earnings or losses of a transferred business before the date of the 2015 Holdings Acquisition allocated entirely to Holdings. The previously reported earnings per unit of the limited partners did not change as a result of the 2015 Holdings Acquisition. See Note 5 to our consolidated financial statements for further details.
(3)
Earnings per unit of Southcross Energy LLC prior to our IPO.

53


(4)
Represents distributions declared with respect to a given period. For example, for the year ended December 31, 2015, represents the distributions declared in April 2015 for the first quarter of 2015, July 2015 for the second quarter of 2015 and October 2015 for the third quarter of 2015. 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.
(5)
See Part II, Item 7 of this report for definition of Non-GAAP financial metrics and reconciliation of such metrics to their most directly comparable GAAP financial measure.
(6)
In accordance with a recently issued accounting standard, deferred issuance costs associated with debt have been reclassified from an asset to a contra-liability for prior periods.


54


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.
We are a master limited partnership, headquartered in Dallas, Texas, 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 four gas processing plants, two fractionation facilities and approximately 3,138 miles of pipeline.
Recent Developments

Holdings Chapter 11 Reorganization

On March 28, 2016, Holdings and certain of its subsidiaries (other than us, our General Partner and our subsidiaries) filed a pre-packaged plan of reorganization (the “POR”) under Chapter 11 of the U.S. Bankruptcy Code in the Southern District of Texas to restructure its debt obligations and strengthen its balance sheet. Our operations, customers, suppliers, partners and other constituents were excluded from such proceeding. On April 11, 2016, the bankruptcy court confirmed Holdings’ POR, and on April 13, 2016, Holdings and its subsidiaries emerged from its bankruptcy and consummated the following principal transactions:

issued 33.34% of the limited partner interests of Holdings to the lenders under Holdings’ credit facility in exchange for the elimination of certain funded debt obligations;

issued 33.33% of the limited partner interests of Holdings to EIG in exchange for approximately $85 million in cash;

issued 33.33% of the limited partner interests of Holdings to Tailwater in exchange for approximately $85 million in cash;

committed to provide us $50 million (as part of the Equity Cure Agreement discussed below), from the $170 million in new equity contributed to Holdings from the Sponsors, to ensure we have sufficient liquidity to comply with the applicable financial covenants set forth in our credit agreement; and

paid all of the receivable due to us.

In addition, pursuant to the terms of the POR, the Lenders have the right to appoint two members (one of which must be independent) to the board of directors of our general partner due to their equity interest in Holdings. The directors appointed by the Lenders will replace the directors previously appointed by Charlesbank Capital Partners, LLC. The court authorized Holdings to continue to pay all of its trade creditors, suppliers and contractors, including us, in the ordinary course of business and any amounts owed by Holdings to these parties will not be impacted by the bankruptcy proceeding. We believe Holdings’ reorganization and POR will enhance our liquidity position, strengthen our balance sheet and position it to continue to support our business and growth.

Holdings Drop-Down Acquisition    

On May 7, 2015, we acquired gathering, treating, compression and transportation assets (the “2015 Holdings

55


Acquisition”) pursuant to a Purchase, Sale and Contribution Agreement among Holdings, TexStar Midstream Utility, LP, Frio LaSalle Pipeline, LP (“Frio”), us and certain of our subsidiaries. The acquired assets consist of the Valley Wells sour gas gathering and treating system (the “Valley Wells System”), compression assets that are part of the Valley Wells and Lancaster gathering and treating systems (the “Compression Assets”) and two NGL pipelines. Total consideration for the assets was $77.6 million, consisting of $15.0 million in cash and 4.5 million new common units, valued as of the date of closing, issued to Holdings. Also, we assumed responsibility for funding the remaining capital expenditures for the completion of the NGL pipelines that were under construction at the time of the acquisition.

The Valley Wells System is located in the Eagle Ford Shale region, in LaSalle County, Texas. The system has sour gas treating capacity of approximately 100 MMcf/d and is supported by a 60 MMcf/d minimum volume commitment from Holdings for gathering and treating services, while Holdings has producer contracts with minimum volume commitments totaling 35 MMcf/d behind the system. The system is connected to our rich gas system for transport and processing. See Notes 1 and 3 to our consolidated financial statements.

Liquidity Consideration
As of December 31, 2015, we were not in compliance with the consolidated total leverage ratio of our Financial Covenants (as defined in Note 8 to our consolidated financial statements) absent an equity cure of $14.9 million. We used the remaining $3.0 million of the contractual $13.0 million non-cash equity cure credit amount from our Credit Agreement Amendment (defined in Note 8 to our consolidated financial statements) to fund a portion of our equity cure. On March 17, 2016, we entered into an equity cure contribution agreement (the “Equity Cure Agreement”) with Holdings whereby we have the right to cure any default with respect to our Financial Covenants by having Holdings purchase equity interests in or make capital contributions to us, in an aggregate amount of up to $50 million. On March 30, 2016, we received $11.9 million from Holdings, pursuant to the terms of the Equity Cure Agreement, to fund the remaining balance of the equity cure required to comply with the consolidated total leverage ratio of our Financial Covenants. In addition, in developing our annual budget for 2016, our forecast indicates future shortfalls in the amount of consolidated EBITDA necessary to remain in compliance with the consolidated total leverage ratio of our Financial Covenants in our Credit Facility for the remainder of 2016. We will have the remaining $38.1 million from the Equity Cure Agreement available to fund additional equity cures through the fourth quarter of 2016, as needed, and to assist in the Partnership's ability to continue as a going concern for a reasonable period of time. We believe that this amount will be sufficient to fund any equity cure requirements during this period. For additional details regarding this equity cure and the Sponsor's equity commitment, see below and Notes 1 and 2 to our consolidated financial statements.
Distribution Suspension
In January 2016 and effective for the fourth quarter of 2015, the board of directors of our General Partner voted not to pay a quarterly distribution and instead to reserve any excess cash for the operation of our business. Quarterly distributions were paid by the Partnership through the third quarter of 2015. The board of directors of our General Partner and our management believe this suspension to be in the best interest of our unitholders. The board of directors and management will continue to evaluate the Partnership's ability to reinstate the distribution in future periods. See Notes 1, 2 and 5 to our consolidated financial statements.
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 US Energy Information Administration (the “EIA”) Texas leads the nation in natural gas production. Almost one-third of the 100 largest natural gas-producing fields in the United States are located, in whole or in part, in Texas. Much of the increase in production is the result of drilling in the Eagle Ford Shale region. Advances in horizontal drilling and hydraulic fracturing technologies, coupled with increased gas prices in the late 1990s, led to significant drilling activity. The Eagle Ford Shale produces substantial amounts of petroleum and natural gas liquids, along with natural gas, from more than 20 fields in 23 counties stretching across South Texas. More than one-fourth of the nation's proved natural gas reserves are located in Texas.

56



The EIA projects natural gas consumption in the United States to average 76.4 billion cubic feet/day (Bcf/d) in 2016 and 77.3 Bcf/d in 2017, compared with 75.4 Bcf/d in 2015. Increases in industrial sector consumption drive total consumption growth in 2016 and 2017. Industrial sector consumption of natural gas increases by 3.3% in 2016 and by 2.3% in 2017, as new projects in the fertilizer and chemicals sectors come online. EIA expects a 0.1 Bcf/d (0.2%) decline in consumption of natural gas for power generation in 2016 and a 0.9% decrease in 2017. Natural gas consumption in the residential and commercial sectors is projected to increase modestly in 2016 and 2017.

In November 2015, total marketed production of natural gas averaged 79.2 Bcf/d, a slight decline from its October level, according to EIA survey data. Small increases in onshore Lower 48 and Alaska production offset a 6% decline in Gulf of Mexico production in November. The EIA estimates that marketed natural gas production averaged 79.1 Bcf/d in 2015, an increase of 4.2 Bcf/d (5.7%) from 2014. EIA projects growth will slow to 0.7% in 2016, as low natural gas prices and declining rig activity begin to affect production. In 2017, however, forecast production growth increases to 2.0%, as forecast prices rise, industrial demand grows, and liquefied natural gas (LNG) exports increase. Production of dry natural gas is forecast to grow by 0.4% in 2016 and by 2.0% in 2017.

The EIA expects U.S. production growth in the forecast period will reduce demand for natural gas imports from Canada and will support growth in exports to Mexico because of growing demand from Mexico's electric power sector coupled with flat natural gas production in Mexico. The EIA projects LNG gross exports will increase to an average of 0.5 Bcf/d in 2016, with the start-up of Cheniere's Sabine Pass LNG liquefaction plant in Louisiana planned for early this year. The EIA projects gross LNG exports will average 1.3 Bcf/d in 2017, as Sabine Pass ramps up its capacity.

The continued depressed natural gas, NGL and crude oil price environment could affect negatively the level of natural gas, NGL and crude oil production which in turn could impact negatively the volume of natural gas flowing on our system.

We expect that the continued long term 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.

Interest Rate Environment

In December 2015, interest rates were raised by the Federal Reserve for the first time since June 2006, signaling that rates may continue to rise in 2016. However, it is expected that economic conditions will evolve in a manner that will warrant only gradual increases in interest rates in 2016, keeping them below levels that are expected to prevail in the longer run. The gradual increases 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. The continued depressed natural gas, NGL and crude oil price environment also could affect negatively our ability to access the debt capital markets.
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 NGLs into the various components and selling or delivering pipeline quality natural gas, Y-grade 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:

57


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, 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 fixed-fee and fixed-spread arrangements for processing services and, therefore, represent only a portion of a 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 operating margins from these arrangements (in thousands):
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
Gross Operating
Margin
 
%
 
Gross Operating Margin
 
%
 
Gross
Operating Margin
 
%
Fixed-fee
$
143,022

(1) 
78.9
%
(1) 
$
90,758

 
71.2
%
 
$
59,532

 
63.7
%
Fixed-spread
15,355

 
8.5
%
 
9,009

 
7.1
%
 
11,143

 
11.9
%
Sub-total
158,377

 
87.4
%
 
99,767

 
78.3
%
 
70,675

 
75.6
%
Commodity-sensitive
22,939

 
12.6
%
 
27,614

 
21.7
%
 
22,871

 
24.4
%
Total gross operating margin
$
181,316

 
100.0
%
 
$
127,381

 
100.0
%
 
$
93,546

 
100.0
%

(1) The increase in fixed-fee gross operating margin and gross operating margin percentage compared to 2014 is due primarily to the increase in activity under our gathering, transportation and other services agreements with Holdings, which have increased fee-based revenue with no associated cost of natural gas or liquids sold.
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 (a) volume, (b) gross operating margin, (c) operations and maintenance expense, (d) Adjusted EBITDA and (e) distributable cash flow.
Volume — We determine and analyze volumes by operating unit, but report overall volumes after elimination of intercompany deliveries. The volume of natural gas and NGLs on our systems depends on the level of production from natural gas wells connected to our systems and also from wells connected with other pipeline systems that are interconnected with our systems.
Gross Operating Margin — Gross operating margin of our contracts is one of the metrics we use to measure and evaluate our performance. Gross operating margin is not a measure calculated in accordance with accounting principles generally accepted in the United States of America (“GAAP”). We define gross operating margin as the sum of revenues less the cost of

58


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 and NGLs and record as an expense the associated cost of natural gas and NGLs sold.
Operations and Maintenance Expense — Our management seeks to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating and maintaining our assets. Direct labor costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operations and maintenance expense. These expenses are relatively stable and largely independent of volumes delivered through our systems, but may fluctuate depending on the activities performed during a specific period.
Adjusted EBITDA and Distributable Cash Flow — We believe that Adjusted EBITDA 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/loss, plus interest expense, income tax expense, depreciation and amortization expense, equity in losses of joint venture investments, certain non-cash charges (such as non-cash unit-based compensation, impairments, loss on extinguishment of debt and unrealized losses on derivative contracts), major litigation costs net of recoveries, transaction-related costs, revenue deferral adjustment, loss on sale of assets and selected charges that are unusual or non-recurring; less interest income, income tax benefit, unrealized gains on derivative contracts, equity in earnings of joint venture investments 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 and income tax benefit, less cash paid for interest (net of capitalized costs), income tax expense and maintenance capital expenditures. We use distributable cash flow to analyze our performance and liquidity. 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.

59


Reconciliations of Non-GAAP Financial Measures
The following table presents a reconciliation of gross operating margin to net loss (in thousands):
 
Year Ended December 31,
 
2015
 
2014
 
2013
Reconciliation of gross operating margin to net loss
 
 
 
 
 
Gross operating margin
$
181,316

 
$
127,381

 
$
93,546

Add (deduct):
 
 
 
 
 
Income tax benefit (expense)
233

 
(52
)
 
(385
)
Equity in losses of joint venture investments
(13,452
)
 
(6,496
)
 

Interest expense
(32,738
)
 
(15,562
)
 
(12,590
)
Loss on extinguishment of debt

 
(2,316
)
 

Other, net

 
(77
)
 

Gain (loss) on sale of assets, net
(416
)
 
(365
)
 
25

General and administrative
(30,026
)
 
(32,723
)
 
(21,764
)
Impairment of assets
(7,067
)
 
(1,556
)
 

Depreciation and amortization
(70,814
)
 
(46,050
)
 
(33,548
)
Operations and maintenance
(82,529
)
 
(59,915
)
 
(41,254
)
Net loss
$
(55,493
)
 
$
(37,731
)
 
$
(15,970
)


60


The following table presents a reconciliation of net cash flows provided by operating activities to net loss, Adjusted EBITDA, and distributable cash flow (in thousands):
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
 
 
 
 
 
Net cash provided by operating activities
$
18,725

 
$
45,628

 
$
15,973

Add (deduct):
 
 
 
 
 
Depreciation and amortization
(70,814
)
 
(46,050
)
 
(33,548
)
Unit-based compensation
(4,573
)
 
(10,074
)
 
(2,186
)
Loss on extinguishment of debt

 
(2,316
)
 

Amortization of deferred financing costs
(3,494
)
 
(2,005
)
 
(1,287
)
Gain (loss) on sale of assets, net
(416
)
 
(365
)
 
25

Unrealized gain (loss) on financial instruments
(110
)
 
(168
)
 
120

Equity in losses of joint venture investments
(13,452
)
 
(6,496
)
 

Impairment of assets
(7,067
)
 
(1,556
)
 

Distribution from joint venture investment
(500
)
 

 

Other, net
82

 
(65
)
 
(130
)
Changes in operating assets and liabilities:
 
 
 
 
 
Trade accounts receivable, including affiliates
3,069

 
24,770

 
6,675

Prepaid expenses and other current assets
495

 
5

 
1,197

Other non-current assets
(296
)
 
29

 
(215
)
Accounts payable and accrued expenses
24,559

 
(35,658
)
 
(1,411
)
Other liabilities, including affiliates
(1,701
)
 
(3,410
)
 
(1,183
)
Net loss
$
(55,493
)
 
$
(37,731
)
 
$
(15,970
)
Add (deduct):
 
 
 
 
 
Depreciation and amortization
$
70,814

 
$
46,050

 
$
33,548

Interest expense
32,738

 
15,562

 
12,590

Unrealized loss (gain) on commodity swaps
111

 
8

 
(120
)
Loss on extinguishment of debt

 
2,316

 

Revenue deferral adjustment
3,016

 
2,514

 

Unit-based compensation
4,573

 
2,931

 
2,186

Income tax (benefit) expense
(233
)
 
52

 
385

Loss (gain) on sale of assets, net
416

 
365

 
(25
)
Major litigation costs, net of recoveries
513

 
1,904

 
517

Equity in losses of joint venture investments
13,452

 
6,496

 

Severance expense
956

 

 

Valley Wells' operating expense cap adjustment
2,670

 

 

Transaction-related costs
2,483

 
9,850

 

Impairment of assets
7,067

 
1,556

 

Other, net
800

(1) 
65

 
1,375

Adjusted EBITDA
$
83,883

 
$
51,938

 
$
34,486

Cash interest, net of capitalized costs
(32,293
)
 
(13,371
)
 
(11,187
)
Income tax benefit (expense)
233

 
(52
)
 
(385
)
Maintenance capital expenditures
(11,618
)
 
(5,777
)
 
(3,353
)
Distributable cash flow
$
40,205

 
$
32,738

 
$
19,561


(1) This amount includes an immaterial amount related to the effects of presenting our financial results on an as-if pooled basis (in connection with the 2015 Holdings Acquisition discussed in Note 3 to our consolidated financial statements).

61


Key Factors Affecting Operating Results and Financial Condition 
Acquisition of rich gas assets from TexStar. In August 2014, we acquired the Lone Star plant, a 300 MMcf/d natural gas processing facility along with joint venture entities that own 175 miles of natural gas gathering and 58 miles of residue pipelines across core producing areas of the liquids-rich window of the Eagle Ford Shale.

New pipelines in operation. In October 2014, we completed construction and commenced operation of the addition to our pipeline system extending into Webb County, Texas (the "Webb Pipeline"). The Webb Pipeline is a 45 mile 24 inch pipeline which connects Eagle Ford Shale region supply to our joint venture pipelines in LaSalle County for further delivery to our processing plants.

Acquisition of Onyx pipelines and contracts. In March 2014, our subsidiary, Southcross Nueces Pipelines LLC, acquired natural gas pipelines in Nueces and San Patricio Counties, Texas and contracts related to these pipelines from Onyx. These pipelines transport natural gas to two power plants in Nueces County, Texas under fixed-fee contracts that extend through 2029 and include an option to extend the agreements by an additional term of up to ten years.

Acquisition of Holdings drop-down assets. In May 2015, we acquired gathering, treating, compression and transportation assets from Holdings and its subsidiaries consisting of the Valley Wells System's sour gas gathering and treating system with sour gas treating capacity of approximately 100 MMcf/d and is supported by a 60 MMcf/d minimum volume commitment from Holdings for gathering and treating services, while Holdings has producer contracts with minimum volume commitments totaling 35 MMcf/d behind the system. The system is connected to our rich gas system for transport and processing. The assets acquired in the 2015 Holdings Acquisition includes over 50,000 horsepower of compression capability that serve both the Valley Wells and Lancaster gathering systems located primarily in Dimmit, Frio and LaSalle counties. The NGL pipelines, which were completed in June 2015, include a Y-grade pipeline that connects our Woodsboro processing facility to Robstown and a propane pipeline from our Bonnie View fractionator to Robstown.


62


Results of Operations
The following table summarizes our results of operations (in thousands, except operating data):
 
Year Ended December 31,
 
2015 (1)
 
2014 (1)
 
2013
Revenues:
 
 
 
 
 
Revenues
$
603,815

 
$
835,246

 
$
634,722

Revenues - affiliates
94,658

 
13,267

 

Total revenues
698,473

 
848,513

 
634,722

Expenses:
 
 
 
 
 
Cost of natural gas and liquids sold
517,157

 
721,132

 
541,176

Operations and maintenance
82,529

 
59,915

 
41,254

Depreciation and amortization
70,814

 
46,050

 
33,548

General and administrative
30,026

 
32,723

 
21,764

Impairment of assets
7,067

 
1,556

 

Loss (gain) on sale of assets, net
416

 
365

 
(25
)
Total expenses
708,009

 
861,741

 
637,717

Loss from operations
(9,536
)
 
(13,228
)
 
(2,995
)
Other expense:
 
 
 
 
 
Equity in losses of joint venture investments
(13,452
)
 
(6,496
)
 

Interest expense
(32,738
)
 
(15,562
)
 
(12,590
)
Loss on extinguishment of debt

 
(2,316
)
 

Other expense

 
(77
)
 

Total other expense
(46,190
)
 
(24,451
)
 
(12,590
)
Loss before income tax benefit (expense)
(55,726
)
 
(37,679
)
 
(15,585
)
Income tax benefit (expense)
233

 
(52
)
 
(385
)
Net loss
$
(55,493
)
 
$
(37,731
)
 
$
(15,970
)
 
 
 
 
 
 
Other financial data:
 
 
 
 
 
Adjusted EBITDA
$
83,883

 
$
51,938

 
$
34,486

Gross operating margin
$
181,316

 
$
127,381

 
$
93,546

 
 
 
 
 
 
Maintenance capital expenditures
$
11,618

 
$
5,777

 
$
3,353

Growth capital expenditures
$
93,718

 
$
162,840

 
$
90,510

 
 
 
 
 
 
Operating data:
 
 
 
 
 
Average volume of processed gas (MMcf/d)
434

 
295

 
219

Average volume of NGLs produced (Bbls/d)
43,234

 
23,252

 
14,180

 
 
 
 
 
 
Realized prices on natural gas volumes ($/Mcf)
$
3.16

 
$
5.28

 
$
4.13

Realized prices on NGL volumes ($/gal)
0.36

 
0.78

 
0.88

_______________________________________________________________________________

(1) The 2015 Holdings Acquisition was deemed a transaction between entities under common control and, as such, was accounted for on an “as if pooled” basis for all periods which common control existed (which began on August 4, 2014). The Partnership’s financial results retrospectively include the financial results of the Valley Wells System and Compression Assets for all periods ending after August 4, 2014, the date of the Holdings Transaction.


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2015 Compared with 2014
Volume and overview. Processed gas volumes increased 139 MMcf/d, or 47%, to 434 MMcf/d during the year ended December 31, 2015, compared to 295 MMcf/d during the year ended December 31, 2014. This increase was due primarily to increased volumes from the TexStar Rich Gas System Transaction and increases in volumes from new and existing customers in the Eagle Ford Shale region. Beginning in the second half of 2014 and continuing through the issuance of these financial statements, commodity prices have experienced increased volatility. In particular, natural gas, crude oil and NGL prices have decreased significantly. Our future cash flow will be materially adversely affected if we continue to experience significant, prolonged pricing deterioration of the commodities we sell or a continued material reduction in drilling for oil and natural gas in the geographic areas in which we operate, including the Eagle Ford Shale region.
NGLs produced at our processing plants for the year ended December 31, 2015 averaged 43,234 Bbls/d, an increase of 86%, or 19,982 Bbls/d, compared to 23,252 Bbls/d for the year ended December 31, 2014. The increase in NGLs produced is due primarily to increased throughput volumes and additional rich gas volumes through our processing plants as a result of the TexStar Rich Gas System Transaction.
Gross operating margin for the year ended December 31, 2015 was $181.3 million, compared to $127.4 million for the year ended December 31, 2014. This increase of $53.9 million, or 42%, was due primarily to increased processed gas volumes and margins on our system, as well as increased transportation, gathering and processing fees.
Adjusted EBITDA increased by $32.0 million, or 62%, to $83.9 million for the year ended December 31, 2015, compared to $51.9 million for the year ended December 31, 2014, due primarily to higher processed gas volumes and margins from processing activities, partially offset by higher operating expenses. We had a net loss of $55.5 million for the year ended December 31, 2015 compared to a net loss of $37.7 million for the year ended December 31, 2014. Net loss increased due primarily to increased operations and maintenance expenses, additional depreciation and amortization expense from acquisitions, increased interest expense from higher average borrowings and increased equity in losses of our joint venture investments, partially offset by increased gross operating margin.
Revenue. Our total revenues for 2015 decreased $150.0 million, or 18%, to $698.5 million compared to $848.5 million in 2014. This decrease was due primarily to a decrease in realized prices in natural gas and NGLs, resulting in revenue from sales of natural gas decreasing by $131.1 million and revenue from sales of NGLs and condensate decreasing by $71.7 million for the year ended December 31, 2015 compared to the year ended December 31, 2014. This decrease was partially offset by increased revenue of $47.9 million resulting from the additional transportation, gathering, and processing fees revenue, and $4.9 million of other revenues. Realized average natural gas and NGL prices were as follows: 
 
Year Ended December 31,
 
2015
 
2014
Natural Gas ($/Mcf)
$3.16
 
$5.28
NGLs ($/Gal)
$0.36
 
$0.78
Cost of natural gas and NGLs sold. Our cost of natural gas and NGLs sold for the year ended December 31, 2015 was $517.2 million, compared to $721.1 million for the year ended December 31, 2014. This decrease of $203.9 million, or 28%, was due primarily to lower natural gas and NGL prices compared to the same period in 2014.
Operations and maintenance expenses. Operations and maintenance expenses for the year ended December 31, 2015 were $82.5 million, compared to $59.9 million for the year ended December 31, 2014. This increase of $22.6 million, or 38%, was due primarily to higher operating costs of $5.6 million, increased lease capacity costs of $4.5 million, higher utilities costs of $4.2 million, and higher taxes of $3.1 million all due primarily to the acquisition of additional assets during the year ended December 31, 2015 compared to the year ended December 31, 2014.
General and administrative expenses. General and administrative expenses for the year ended December 31, 2015 were $30.0 million, compared to $32.7 million for the year ended December 31, 2014. This decrease of $2.7 million, or 8%, was due primarily to $6.6 million of one-time compensation expense in the third quarter of 2014 from the accelerated vesting of the LTIP awards, as a result of the change in control in August 2014, partially offset by increased labor and benefits costs of $4.3 million from employee additions for the year ended December 31, 2015 as compared to the year ended December 31, 2014.
Depreciation and amortization expense. Depreciation and amortization expense for the year ended December 31, 2015 was $70.8 million, compared to $46.0 million for the year ended December 31, 2014. The increase of $24.8 million, or 54%, was due primarily to depreciation of the TexStar Rich Gas System assets acquired in the third quarter of 2014, the 2015 Holdings Acquisition and other capital projects placed in service during the second half of 2014.

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Equity in losses of joint venture investments.  Our share of losses incurred by the joint venture investments acquired as part of the TexStar Rich Gas System assets was $13.5 million for the year ended December 31, 2015 compared to $6.5 million for the year ended December 31, 2014. This increase of $7.0 million, or 108%, was due to the fact that the joint venture investments were acquired on August 4, 2014, and thus the 2014 amount only includes five months of activity. We pay our proportionate share of the joint ventures’ operating costs, excluding depreciation and amortization, through lease capacity payments. As a result, our share of the joint ventures’ losses is related primarily to the joint ventures’ depreciation and amortization.

Loss on extinguishment of debt.  For the year ended December 31, 2014, we incurred a loss on the extinguishment of debt of $2.3 million in connection with the write-off of deferred financing costs related to exiting the Previous Credit Facility and entering into the Senior Credit Facilities in August 2014.

Impairment of assets.  For the year ended December 31, 2015, we incurred impairment on our assets of $7.1 million, compared to $1.6 million for the year ended December 31, 2014. This increase of $5.5 million was due primarily to impairment costs attributed to a spare turbine.
Interest expense. For the year ended December 31, 2015, interest expense was $32.7 million, compared to $15.6 million for the year ended December 31, 2014. This increase of $17.1 million, or 110%, was due to higher average borrowings related primarily to the debt incurred as part of the TexStar Rich Gas System and higher interest rates on borrowings.
2014 Compared with 2013
Volume and overview. Processed gas volumes increased 76 MMcf/d, or 35%, to 295 MMcf/d during the year ended December 31, 2014, compared to 219 MMcf/d during the year ended December 31, 2013. This increase was due primarily to increased volumes from the TexStar Rich Gas System Transaction and increases in volumes from new and existing customers in the Eagle Ford Shale producing area.
NGLs produced at our processing plants for the year ended December 31, 2014 averaged 23,252 Bbls/d, an increase of 9,071 Bbls/d, or 64%, compared to 14,180 Bbls/d for the year ended December 31, 2013. This increase was due primarily to the impact of additional volumes of rich gas on our system and enhanced operational efficiency at our facilities during the year ended December 31, 2014 compared to the year ended December 31, 2013. 
Gross operating margin for the year ended December 31, 2014 was $127.4 million, compared to $93.5 million for the year ended December 31, 2013. This increase of $33.9 million, or 36%, was due primarily to increased processed gas volumes on our system, as well as increased transportation, gathering and processing fees.
Adjusted EBITDA increased by $17.4 million, or 50%, to $51.9 million for the year ended December 31, 2014, compared to $34.5 million for the year ended December 31, 2013, due to higher processed gas volumes and margins from processing and fractionation activities, partially offset by higher operating and general and administrative expenses. We had a net loss of $37.7 million for the year ended December 31, 2014 compared to a net loss of $16.0 million for the year ended December 31, 2013. Net loss increased due to higher overall expenses, including transaction-related costs affiliated with the Holdings Transaction and the TexStar Rich Gas System Transaction, and equity in losses of our joint venture investments, partially offset by higher gross operating margin.
Revenue. Our total revenues for 2014 increased 34% to $848.5 million compared to $634.7 million in 2013. This increase of $213.8 million was due primarily to greater revenue from sales of natural gas of $125.7 million, greater revenues of NGLs and condensate of $56.7 million and higher revenue from transportation, gathering and processing fees of $25.6 million.  Realized average natural gas and NGL prices were as follows: 
 
Year Ended December 31,
 
2014
 
2013
Natural Gas ($/Mcf)
$5.28
 
$4.13
NGLs ($/Gal)
$0.78
 
$0.88
Cost of natural gas and NGLs sold. Our cost of natural gas and NGLs sold for the year ended December 31, 2014 was $721.1 million, compared to $541.2 million for the year ended December 31, 2013. This increase of $179.9 million, or 33%, was due primarily to increased natural gas volumes purchased, increased NGL volumes purchased and higher natural gas prices compared to the same period in 2013.
Operations and maintenance expenses. Operations and maintenance expenses for the year ended December 31, 2014 were $59.9 million, compared to $41.3 million for the year ended December 31, 2013. This increase of $18.6 million, or 45%,

65


was due primarily to $3.0 million from higher labor costs including employee additions, $2.0 million from the accelerated vesting of our LTIP awards (which occurred as a result of our change of control in August 2014), higher fees of $1.5 million and higher operating costs of $1.4 million due to the acquisition of additional assets during the year ended December 31, 2014 compared to the year ended December 31, 2013.
General and administrative expenses. General and administrative expenses for the year ended December 31, 2014 were $32.7 million, compared to $21.8 million for the year ended December 31, 2013. This increase of $10.9 million, or 50%, was due primarily to increased expenses related to labor and benefits costs of $6.6 million from the accelerated vesting of LTIP awards (which occurred as a result of our change of control in August 2014), and $1.2 million from employee additions, together with higher professional fees of $2.5 million, mostly related to the TexStar Rich Gas System Transaction. Additionally, in the fourth quarter of 2014, the accrual for discretionary bonus was reduced after consideration of operating results.
Depreciation and amortization expense. Depreciation and amortization expense for the year ended December 31, 2014 was $46.0 million, compared to $33.5 million for the year ended December 31, 2013. The increase of $12.5 million, or 37%, was due primarily to depreciation of the TexStar Rich Gas System and 2015 Holdings Acquisition assets acquired in the third quarter of 2014 and other capital projects placed in service during 2014.
Equity in losses of joint venture investments.  Our share of losses incurred by the joint venture investments acquired as part of the TexStar Rich Gas System assets was $6.5 million for the period from August 4, 2014 through December 31, 2014. We pay for our proportionate share of the joint ventures’ operating costs, excluding depreciation and amortization through lease capacity payments. As a result, our share of the joint ventures’ losses are primarily related to the joint ventures’ depreciation and amortization.

Loss on extinguishment of debt.  For the year ended December 31, 2014, we incurred a loss on the extinguishment of debt of $2.3 million in connection with the write-off of deferred financing costs related to exiting the Previous Credit Facility and entering into the Senior Credit Facilities in August 2014.
Interest expense. For the year ended December 31, 2014, interest expense was $15.6 million, compared to $12.6 million for the year ended December 31, 2013. This increase of $3.0 million, or 24%, was due to higher average borrowings related primarily to the debt incurred as part of the TexStar Rich Gas System.
Liquidity and Capital Resources
Sources of Liquidity
Our primary sources of liquidity are cash generated from operations, cash raised through issuances of additional equity and debt securities and borrowings under our Senior Credit Facilities (as defined in Note 8 to our consolidated financial statements). Our primary cash requirements consist of operating and maintenance and general and administrative expenses, growth and maintenance capital expenditures to sustain existing operations or generate additional revenues, interest payments on outstanding debt, purchases and construction of new assets, business acquisitions and distributions to unitholders.
We expect to fund short-term cash requirements, such as operating and maintenance and general and administrative 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 Senior Credit Facilities and issuances of additional debt and equity securities (including the issuance of units to Holdings), as appropriate and subject to market conditions. See Note 8 to our consolidated financial statements.
Beginning in the second half of 2014 and continuing through the issuance of this annual report, commodity prices have experienced increased volatility. In particular, natural gas, crude oil and NGL prices have decreased significantly. Our future cash flow will be materially adversely affected if prolonged pricing deterioration continues for the commodities we sell or if a material reduction in drilling for oil or natural gas continues in the geographic areas in which we operate, including the Eagle Ford Shale region. See Note 2 to our consolidated financial statements.
The majority of our revenue is derived from fixed-fee contracts, which have limited direct exposure to commodity price levels since 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 being paid based on the value of the underlying natural gas or NGLs. In addition, a percentage of our contract portfolio contains minimum volume commitment arrangements. The majority of our volumes are dependent upon the level of producer drilling activity.
After considering these uncertainties, and in developing our annual budget for 2016, our forecast indicates future shortfalls in the amount of consolidated EBITDA (as defined in the Third Amended and Restated Revolving Credit Agreement with Wells Fargo Bank, N.A., as Administrative Agent, UBS Securities LLC and Barclays Bank PLC, as Co-Syndication

66


Agents, JPMorgan Chase Bank, N.A., as Documentation Agent, and a syndicate of lenders (the “Third A&R Revolving Credit Agreement”) necessary to remain in compliance with the consolidated total leverage ratio of our Financial Covenants in our Credit Facility for the remainder of 2016. As discussed in further detail in Note 8 to our consolidated financial statements, we have the right to cure such a Financial Covenant Default by either our Sponsors or Holdings purchasing equity interests in or making capital contributions (an equity cure) resulting in, among other things, proceeds that, if added to consolidated EBITDA, would result in us satisfying the Financial Covenants. Once such an equity cure is made, it is included in our consolidated EBITDA calculation in any rolling twelve month period that includes the quarter that was cured. Should there be an event of default under the Credit Facility, and such default is not cured, we would also experience a cross default under our Term Loan Agreement (defined in Note 8 to our consolidated financial statements) and all of our debt would become due and payable to our lenders.
As of December 31, 2015, we were not in compliance with the consolidated total leverage ratio of our Financial Covenants (as defined in Note 8 to our consolidated financial statements) absent an equity cure of $14.9 million that we funded on March 30, 2016. We used the remaining $3.0 million of the contractual $13.0 million non-cash equity cure credit amount from our Credit Agreement Amendment (defined in Note 8 to our consolidated financial statements) to fund a portion of our equity cure as of December 31, 2015. We received the remaining $11.9 million shortfall from Holdings pursuant to the terms of our Equity Cure Agreement. We used $10.0 million of the contractual $13.0 million non-cash equity cure credit amount from our Credit Agreement Amendment to fund equity cures as of June 30, 2015 and September 30, 2015 in order to stay in compliance with the consolidated total leverage ratio of our Financial Covenants. For additional details regarding this equity cure, see Notes 1 and 2 to our consolidated financial statements. We anticipate funding additional equity cures needed to maintain compliance with our Financial Covenants through the end of 2016 with the additional equity commitment under the Equity Cure Agreement that will assist in the Partnership's ability to continue as a going concern for a reasonable period of time.
In connection with Holdings' Chapter 11 reorganization, Holdings has committed to contribute up to $50 million to us (the “Contribution Amount”) to ensure we have sufficient liquidity to comply with applicable Financial Covenants through the quarter ended December 31, 2016. In exchange for the Contribution Amount, we will issue Holdings a number of our common units representing limited partner interests equal to, subject to certain exceptions, (i) the applicable Contribution Amount divided by (ii) a common unit reference price (“Reference Price”) equal to the volume weighted daily average price of the common units on the New York Stock Exchange (“VWAP”) calculated for a period of 15 trading days ending two trading days prior to the contribution by Holdings. Notwithstanding the VWAP calculation, the Reference Price will be no less than $0.89 per common unit and no greater than $1.48 per common unit (the “Range”), and if the VWAP is within the Range for a period of 15 trading days, the first of which is the tenth trading day following March 28, 2016, the date of the announcement, such VWAP will be the Reference Price for all common units issued in exchange for the Contribution Amount. The $11.9 million necessary to cure the non-compliance in the fourth quarter of 2015 was contributed to us under the terms of the debtor in possession (“DIP”) arrangement agreed to in the Holdings' Chapter 11 reorganization proceedings discussed above and in Notes 1 and 2 to our consolidated financial statements. In accordance with the requirements above and the amount funded for this equity cure, Holdings will be issued between 8.0 million and 13.4 million common units. However, the exact number of units to be issued to Holdings in exchange for this contribution has yet to be determined due to the required number of days to calculate the VWAP not being reached as of the date of the issuance of these financial statements.
On January 7, 2016, in response to our need for additional liquidity, we issued at par Senior Unsecured PIK Notes in the aggregate principal amount of $14 million (the "PIK Notes") to affiliates of EIG and Tailwater (collectively, the "PIK Lenders"), that bear interest at a rate of 7% per annum, payable in cash or, at the option of the Partnership, in-kind. The PIK Notes will mature on January 7, 2017. Subsequent to the balance sheet date, but prior to the issuance of our annual report, and in accordance with the POR, the PIK Notes and the related interest were repaid in full.
In addition, subsequent to the balance sheet date, but prior to the issuance of our annual report, the receivable due from Holdings of $43.0 million was brought current. See Note 2 to our consolidated financial statements.
As of April 8, 2016, we had $624.9 million in outstanding borrowings under our Senior Credit Facilities. Under our five-year revolving credit facility, pursuant to our Third A&R Revolving Credit Agreement, we have the ability to borrow up to $200.0 million (the "Credit Facility") less any letters of credit amounts outstanding, which as of April 8, 2016 provided us access to $0.8 million.
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 include:
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, but exclude expenditures for acquisitions; and

67


maintenance capital expenditures, which are capital expenditures that are not considered growth capital expenditures.

The following table summarizes our capital expenditures (in thousands):
 
 
Year Ended December 31,
 
2015
 
2014
Maintenance capital
$
11,618

 
$
5,777

Growth capital
93,718

 
162,840

Total capital expenditures
$
105,336

 
$
168,617


Growth capital expenditures during the year ended December 31, 2015 relate primarily to various expansion and improvement projects primarily in our South Texas assets. The growth capital expenditures during the year ended December 31, 2014 related primarily to construction of the Webb Pipeline, Valley Wells System and Compression Assets.
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.
Our ability to benefit from growth projects to accommodate 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.
We believe that cash from operations, cash on hand and the sale of equity to Holdings under the Contribution Amount will provide liquidity to meet future short-term capital requirements for a reasonable period of time. 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 Senior Credit Facilities. We believe we have and will continue to have sufficient liquidity to operate our business. See Notes 2 and 8 to our consolidated financial statements.
Growth 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,
 
2015
 
2014
 
2013
Net cash provided by operating activities
$
18,725

 
$
45,628

 
$
15,973

Net cash used in investing activities
(127,837
)
 
(288,427
)
 
(97,109
)
Net cash provided by financing activities
118,811

 
241,099

 
76,995

2015 Compared with 2014
Operating Activities—Net cash provided by operating activities was $18.7 million for the year ended December 31, 2015, compared to $45.6 million for the year ended December 31, 2014. The decrease in cash provided by operating activities of $26.9 million was primarily the result of decreased net earnings during the year ended December 31, 2015 compared to the year ended December 31, 2014, as well as not having collected a receivable of $43.0 million from Holdings. 

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Investing Activities—Net cash used in investing activities was $127.8 million for the year ended December 31, 2015, compared to $288.4 million for the year ended December 31, 2014. The decrease relates primarily to the TexStar Rich Gas System Transaction in August 2014, the Onyx acquisition in March 2014 and decreased capital expenditures, partially offset by the cash consideration paid in the 2015 Holdings Acquisition.
Financing Activities—Net cash provided by financing activities was $118.8 million for the year ended December 31, 2015, compared to $241.1 million for the year ended December 31, 2014. The decrease of $122.3 million was due to proceeds received from our $144.7 million equity offering, net of expenses, in the first quarter of 2014 and reduced net borrowings of $63.3 million from our debt instruments and decreased financing costs, partially offset by $100 million of debt assumed and immediately repaid by us in connection with the TexStar Rich Gas System Transaction.
2014 Compared with 2013
Operating activities—Net cash provided by operating activities was $45.6 million for the year ended December 31, 2014, compared to $16.0 million for the year ended December 31, 2013. The increase in cash provided by operating activities of $29.6 million was primarily the result of increased gross operating margin during the year ended December 31, 2014 compared to the year ended December 31, 2013. In addition, the net changes in working capital of $17.0 million caused an increase in operating cash flows for the year ended December 31, 2014 compared to the year ended December 31, 2013.
Investing activities—Net cash used in investing activities was $288.4 million for the year ended December 31, 2014, compared to $97.1 million for the year ended December 31, 2013. The increase of $191.3 million related primarily to the TexStar Rich Gas System Transaction and the 2015 Holdings Acquisition in August 2014, the Onyx acquisition in March 2014 and increased capital expenditures in 2014.
Financing activities—Net cash provided by financing activities was $241.1 million for the year ended December 31, 2014, compared to $77.0 million for the year ended December 31, 2013. The increase was due to proceeds received from our $144.7 million equity offering, net of expenses, in the first quarter of 2014, as well as additional net borrowings of $134.2 million from our debt instruments, and $50.6 million of expenses paid by Holdings on behalf of the Valley Wells System. The increase in cash provided by financing activities was partially offset by $100 million of debt assumed and immediately repaid by us in connection with the TexStar Rich Gas System Transaction, increased distributions paid of $16.7 million and additional financing costs of $15.6 million associated with the Senior Credit Facilities.
Senior Credit Facilities

On August 4, 2014, in connection with the consummation of the Holdings Transaction and acquisition of the TexStar Rich Gas System, we entered into the Senior Credit Facilities. See Note 8 to our consolidated financial statements.

The borrowings under our Credit Facility bear interest at the London Interbank Offered Rate (“LIBOR”) or a base rate plus an applicable margin as defined in the Third A&R Revolving Credit Agreement. As of December 31, 2015, our margin was LIBOR plus 3.25% and the outstanding balance of the Credit Facility was $181.7 million with no remaining unused portion.

The borrowings under our seven-year $450 million senior secured term loan facility (the "Term Loan") under the Term Loan Credit Agreement bear interest at LIBOR plus 4.25% with a LIBOR floor of 1.00% or a base rate plus a margin as defined in that agreement. On August 4, 2014, the lenders funded the full amount of the Term Loan. As of December 31, 2015, the outstanding principal balance of the Term Loan was $441.5 million, net of original issuance discount of $1.8 million, and our borrowing rate was 5.25%. We are required to make quarterly amortization payments towards the Term Loan.

As of December 31, 2015, after using an equity cure of $14.9 million to stay in compliance with the consolidated total leverage ratio of our Financial Covenants, we were in compliance with the covenants set forth in the Senior Credit Facilities. Additionally, the annual financial statements of the Partnership were not filed timely as required under the Senior Credit Facilities and the issuance of the financial statements on April 14, 2016 cures such potential event of default. See Notes 2 and 8 to our consolidated financial statements.
Equity Distribution Agreement
On November 12, 2014, we established a $75 million “at-the-market” equity offering program pursuant to an equity distribution agreement (the “Distribution Agreement”) with Wells Fargo Securities, LLC, J.P. Morgan Securities LLC and RBC Capital Markets, LLC (each, a “Manager” and, collectively, the “Managers”). Under the Distribution Agreement, we may offer and sell up to $75 million in aggregate gross sales proceeds of our common units (the “Offered Units”) from time to time through the Managers, each as our sales agent. Sales of the Offered Units, if any, made under the Distribution Agreement will

69


be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices prevailing at the time of sale in block transactions, or as otherwise agreed upon by us and any Manager. The Offered Units have been registered under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Registration No. 333-192105 declared effective December 10, 2013, including the prospectus contained therein, as supplemented by the prospectus supplement filed with the SEC on November 12, 2014. We intend to use the net proceeds from the sale of the Offered Units, if any, for general partnership purposes, including the repayment of debt, acquisitions and funding capital expenditures. As of December 31, 2015, we have not sold any of the Offered Units pursuant to the Distribution Agreement.
The Distribution Agreement contains customary representations, warranties and agreements by us, including our obligations to indemnify the Managers for certain liabilities under the Securities Act. The Managers and certain of their affiliates have engaged, and may in the future engage, in commercial and investment banking transactions with us in the ordinary course of their business for which they have received, and expect to receive, customary compensation and expense reimbursement. In particular, affiliates of each of the Managers are lenders under our Senior Credit Facilities, an affiliate of Wells Fargo Securities, LLC is a lender under our Term Loan Agreement, and affiliates of the other sales agents may from time to time hold positions under the Term Loan Agreement. If we use any net proceeds of this offering to repay borrowings under our Senior Credit Facilities, such affiliates of the Managers will receive proceeds of the offering.
Equity Cure Contribution Agreement
On March 17, 2016, the Partnership and Holdings entered into the Equity Cure Agreement related to the Third A&R Revolving Credit Agreement. Under the terms of the Third A&R Revolving Credit Agreement, the Partnership has the right to cure any default with respect to a financial covenant in the Third A&R Revolving Credit Agreement by having Holdings purchase equity interests in or make capital contributions to the Partnership that result in proceeds that would satisfy the requirements of such financial covenant.
Pursuant to the Equity Cure Agreement, Holdings has agreed to contribute the Contribution Amount to the Partnership to fund potential equity cures upon notification from the Partnership that a contribution would cure any default of a financial covenant in the Revolving Credit Agreement occurring through the quarter ended December 31, 2016. In exchange for the Contribution Amount, the Partnership will issue Holdings a number of the Partnership's common units representing limited partner interests equal to, subject to certain exceptions, (i) the applicable Contribution Amount divided by (ii) the Reference Price. Notwithstanding the VWAP calculation, the Reference Price will be within the Range, and if the VWAP is within the Range for a period of 15 trading days, the first of which is the tenth trading day following March 28, 2016, the date of the announcement, such VWAP will be the Reference Price for all common units issued in exchange for the Contribution Amount. It is expected that funding of any amount under the Contribution Agreement would be from funds received by Holdings from the proceeds of the equity investment contemplated under, and after the effectiveness of, the plan of reorganization for Holdings.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements.
Contractual Obligations
The following table summarizes our contractual obligations as of December 31, 2015 (in thousands):
 
 
Total
 
Less Than 1 Year
 
1-3 Years
 
3-5 Years
Long-term debt:
 
 
 
 
 
 
 
 
Principal(1)
$
609,018

 
$
4,500

 
$
9,000

 
$
190,695

 
Interest(2)
125,916

 
32,149

 
64,297

 
29,470

Vehicle fleet lease
908

 
373

 
301

 
235

Office lease
4,450

 
1,141

 
2,254

 
1,055

Total
$
740,292

 
$
38,162

 
$
75,852

 
$
221,455

_______________________________________________________________________________
(1)
Contractual obligations related to the Credit Facility assume the $181.7 million outstanding as of December 31, 2015 is paid off at maturity in November 2019. Contractual obligations of the Term Loan are net of original issuance discount of $1.8 million.

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(2)
Interest is estimated at the weighted average interest rate for the year ended December 31, 2015 of 5.16% for periods through November 2019. The interest does not include interest rate swaps because they are considered to be immaterial.
At December 31, 2015, we had commitments of approximately $4.2 million related primarily to the purchase of pipelines and compressors for our various capital expansion projects which are not included in the table above. We have other planned capital projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.
Critical Accounting Policies
The accounting policies described below are considered critical to obtaining an understanding of our consolidated financial statements because their application requires significant estimates and judgments by management in preparing our consolidated financial statements. Management's estimates and judgments are inherently uncertain and may differ significantly from actual results achieved. Management considers an accounting estimate to be critical if the following conditions apply:
the estimate requires significant assumptions; and
changes in the estimate could have a material effect on our consolidated statements of operations or financial condition; or
if different estimates that could have been selected had been used, there could be a material effect on our consolidated statements of operations or financial condition.
We have discussed the selection and application of these accounting estimates with the Audit Committee of the board of directors of our general partner and our independent registered public accounting firm. It is management's view that the current assumptions and other considerations used to estimate amounts reflected in our consolidated financial statements are appropriate. However, actual results can differ significantly from those estimates under different assumptions and conditions.
Revenue Recognition
Using the revenue recognition criteria of persuasive evidence that an exchange arrangement exists, delivery has occurred or services have been rendered and the price is fixed or determinable, we record natural gas and NGL revenue in the period when the physical product is delivered to the customer and in an amount based on the pricing terms of an executed contract. Our transportation, compression, processing, fractionation and other revenue is recognized in the period when the service is provided and includes our fee-based service revenue. In addition, collectability is evaluated on a customer-by-customer basis. New customers are subject to a credit review process, which evaluates the customers' financial position and their ability to pay.
Our sale and purchase arrangements are primarily accounted for on a gross basis in the statements of operations. These transactions are contractual arrangements that establish the terms of the purchase of natural gas or NGLs at a specified location and the sale of natural gas or NGLs at a different location on the same or on another specified date. These transactions require physical delivery and transfer of the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk.
Certain of our gas gathering agreements provide for a monthly, quarterly or annual minimum volume commitment ("MVC") from our customers. Under these MVCs, our customers agree to ship and/or process a minimum volume of production on our system or to pay a minimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to us at the end of the contracted measurement period if its actual throughput volumes are less than its MVC for that period. Certain customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent contracted measurement periods to the extent that such customer's throughput volumes in a subsequent contracted measurement period exceed its MVC for that period. We recognize customer billings for obligations under their MVCs as revenue when the obligations are billable under the contract and the customer does not have the right to utilize shortfall payments to offset gathering fees in excess of its MVCs in subsequent periods.
Impairment of Long-Lived Assets
We evaluate our long-lived assets, which include finite-lived intangible assets, for impairment when events or circumstances indicate that their carrying values may not be recoverable. These events include, but are not limited to, market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, we evaluate the recoverability of our carrying value based on the long-lived asset's ability to generate future cash flows on an undiscounted basis. If the undiscounted cash flows are not sufficient to recover the long-lived asset's carrying value, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying values of the asset downward, if necessary, to their estimated fair value. Our fair value estimates are generally based on assumptions market participants would

71


use, including market data obtained through the sales process or an analysis of expected discounted cash flows. With the recent decline in commodity prices negatively affecting the level of natural gas and crude oil production, we concluded that a triggering event had occurred which required we test for impairment of our assets. Our undiscounted cash flows were in excess of our long-lived assets' carrying value. However, during the year ended December 31, 2015, we recorded $7.1 million of impairment costs related primarily to a spare turbine. During the year ended December 31, 2014, we recorded $1.6 million of impairment costs related primarily to right-of-way costs on a canceled project. At December 31, 2013, we did not record any impairments of long-lived assets.
New Accounting Pronouncements
For a complete description of new accounting pronouncements, see Note 1 to our consolidated financial statements.
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate. Both profitability and cash flow are affected by volatility in the prices of these commodities. Natural gas and NGL prices are impacted by changes in the supply and demand for natural gas and NGLs, as well as market uncertainty, particularly in the depressed energy pricing environment that began in the second half of 2014. Adverse effects on cash flow from increases or reductions in natural gas and NGL product prices could adversely affect our ability to make distributions to unitholders. We manage this commodity price exposure through an integrated strategy that includes management of the commercial terms of our contract portfolio by entering into fixed-fee-based or fixed-spread arrangements whenever possible and the use of swing swaps. Swing swaps are generally short-term in nature (one month) and are usually entered into to protect against changes in the volume of daily versus first-of-month index priced gas supplies or markets. We have not entered into any long-term derivative contracts to manage exposure to commodity price risk. Natural gas and NGL prices, however, also can affect profitability indirectly by influencing the level of drilling activity in our areas of operation. We are a net seller of NGLs and, as such, financial results also are exposed to fluctuations in NGL price levels.
A hypothetical increase or decrease in commodity prices by 1.0%, absent any volume changes, would have changed our gross operating margin by $0.1 million for the years ended December 31, 2015 and 2014, respectively.
Interest Rate Risk
We have exposure to changes in interest rates on indebtedness. We manage our exposure to interest rate fluctuations by entering into interest rate derivative instruments that include interest rate swaps, caps and floors.  These contracts reduce our exposure to interest rate volatility and result in primarily fixed rate debt when considering the combination of the variable rate debt and the interest rate derivative instrument.
Under the terms of our interest rate swap agreements, we receive a floating rate based upon LIBOR and pay a fixed rate. In 2014, we entered into interest rate swap contracts with a weighted average fixed rate of 0.69% to reduce our exposure to interest rate volatility on $240.0 million notional amount of debt, of which $140.0 million matured in 2015 and $100.0 million will mature in 2016. In 2015, we entered into a swap with a notional amount of $100.0 million that matures in 2017, and paid a fixed rate of 1.20%.
In December 2014, we entered into an interest rate cap contract for $20.0 million notional amount of debt with a maturity date of December 31, 2016. The contract effectively caps our LIBOR-based interest rate on that portion of debt at 1.5%. In June 2015, we entered into a cap for $80.0 million notional amount of debt with a maturity of June 2017. In December 2015, we entered into a cap with a notional amount of $50.0 million with a maturity of December 2017. Both caps entered into in 2015 effectively cap our LIBOR-based interest rate at 3.0%
A hypothetical increase or decrease in interest rates by 1.0% would have changed our interest expense by $3.6 million and $3.2 million for the years ended December 31, 2015 and 2014, respectively.
Risk Relating to NGLs
Recovery Commitments
We have operational exposure under several gas supply and transportation agreements that contain fixed percentage NGL recovery obligations. To the extent that we do not produce, sell or re-deliver under transportation agreements at least as many gallons of NGLs as required under those respective supply and transportation agreements, we are exposed to the equivalent replacement cost of the respective NGL products at NGL market prices net of contractual discounts, offset by the value of the unrecovered NGL products sold at methane natural gas prices. Similarly, to the extent that we produce, sell or re-deliver more

72


gallons of NGL under transportation agreements than required under these agreements, we are able to sell the excess NGL products for our own account.
A hypothetical increase or decrease in NGL volumes recovered of 1.0% would have changed our gross operating margin by $0.5 million and $0.7 million for the years ended December 31, 2015 and 2014, respectively.
Pricing Differential
We are exposed to the risk that we will be unable to sell NGLs at the expected differential to index prices necessary to preserve fixed-spread margins. To the extent that we do not produce marketable purity NGL products, due to operational disruptions or NGL market disruptions, we could realize lower than expected differentials to index prices. This risk is managed by monitoring the supply and demand of our markets, as well as the pricing indices relevant to our products.
A hypothetical increase or decrease of $0.01 in our realized NGL gross operating margin spread per gallon would have changed our gross operating margin by $4.3 million and $2.9 million for the years ended December 31, 2015 and 2014, respectively.
Credit Risk
We are subject to risk of loss resulting from nonpayment by our customers to whom we provide midstream services or sell natural gas or NGLs. Our credit exposure related to these customers is represented by the value of our trade receivables. Where exposed to a significant credit risk, we analyze the customer's financial condition prior to entering into a transaction or agreement, establish credit terms and monitor the appropriateness of these terms on an ongoing basis. In the event of a customer default, we may sustain a loss and our cash receipts could be negatively impacted.


73


Item 8.
Financial Statements and Supplementary Data
SOUTHCROSS ENERGY PARTNERS, L.P.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 
Page
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2015 and 2014
Consolidated Statements of Operations for the Years Ended December 31, 2015, 2014 and 2013
Consolidated Statements of Comprehensive Loss for the Years Ended December 31, 2015, 2014 and 2013
Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013
Consolidated Statements of Changes in Partners' Capital for the Years Ended December 31, 2015, 2014 and 2013
Notes to Consolidated Financial Statements
Supplemental Financial Information
 


74


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Southcross Energy Partners GP, LLC and the unitholders of Southcross Energy Partners, L.P.
Dallas, Texas

We have audited the accompanying balance sheets of Southcross Energy Partners, L.P., and subsidiaries (the "Partnership") as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive loss, changes in partners’ capital, and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2, the Partnership has obtained a commitment through an Equity Cure Contribution Agreement from Southcross Holdings LP, which controls the General Partner of the Partnership, to assist the Partnership in maintaining compliance with its financial covenants for a reasonable period of time.  Also, as discussed in Notes 1 and 3, the Partnership’s financial statements include the results from the TexStar Rich Gas System and the 2015 Holdings Acquisition beginning on August 4, 2014, the date at which common control began.


/s/ Deloitte & Touche LLP


Dallas, Texas
April 14, 2016



75


SOUTHCROSS ENERGY PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands, except for unit data)
 
December 31, 2015
 
December 31,
2014
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
11,348

 
$
1,649

Trade accounts receivable
39,585

 
74,086

Accounts receivable - affiliates
49,734


11,325

Prepaid expenses
3,915

 
3,073

Other current assets
1,256

 
1,813

Total current assets
105,838

 
91,946

 
 
 
 
Property, plant and equipment, net
1,066,001

 
1,058,570

Investments in joint ventures
140,526

 
147,098

Other assets
6,595

 
2,098

Total assets
$
1,318,960

 
$
1,299,712

 
 
 
 
LIABILITIES AND PARTNERS' CAPITAL
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued liabilities
$
66,458

 
$
116,842

Accounts payable - affiliates
7,871

 
12,856

Current portion of long-term debt
4,500

 
4,500

Other current liabilities
10,406

 
12,773

Total current liabilities
89,235

 
146,971

 
 
 
 
Long-term debt
604,518

 
454,527

Other non-current liabilities
3,871

 
1,110

Total liabilities
697,624

 
602,608

 
 
 
 
Commitments and contingencies (Note 9)

 

 
 
 
 
Partners' capital:
 
 
 
Common units (28,420,619 and 23,800,943 units outstanding as of December 31, 2015 and 2014, respectively)
271,236

 
259,735

Class B Convertible units (15,958,990 and 14,889,078 units issued and outstanding as of December 31, 2015 and 2014, respectively)
300,596

 
298,833

Subordinated units (12,213,713 units issued and outstanding as of December 31, 2015 and 2014)
37,920

 
48,831

General partner interest
11,584

 
12,385

Southcross Holdings' equity in contributed subsidiaries

 
77,320

Total partners' capital
621,336

 
697,104

Total liabilities and partners' capital
$
1,318,960

 
$
1,299,712

See accompanying notes to these consolidated financial statements.


76


SOUTHCROSS ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except for per unit data)
 
Year Ended December 31,
 
2015
 
2014
 
2013
Revenues:
 
 
 
 
 
Revenues
$
603,815

 
$
835,246

 
$
634,722

Revenues - affiliates
94,658

 
13,267

 

Total revenues (Note 14)
698,473

 
848,513

 
634,722

 
 
 
 
 
 
Expenses:
 
 
 
 
 
Cost of natural gas and liquids sold
517,157

 
721,132

 
541,176

Operations and maintenance
82,529

 
59,915

 
41,254

Depreciation and amortization
70,814

 
46,050

 
33,548

General and administrative
30,026

 
32,723

 
21,764

Impairment of assets
7,067

 
1,556

 

Loss (gain) on sale of assets, net
416

 
365

 
(25
)
Total expenses
708,009

 
861,741

 
637,717

 
 
 
 
 
 
Loss from operations
(9,536
)
 
(13,228
)
 
(2,995
)
Other expense:
 
 
 
 
 
Equity in losses of joint venture investments
(13,452
)
 
(6,496
)
 

Interest expense
(32,738
)
 
(15,562
)
 
(12,590
)
Loss on extinguishment of debt

 
(2,316
)
 

Other expense

 
(77
)
 

Total other expense
(46,190
)
 
(24,451
)
 
(12,590
)
Loss before income tax benefit (expense)
(55,726
)
 
(37,679
)
 
(15,585
)
Income tax benefit (expense)
233

 
(52
)
 
(385
)
Net loss
(55,493
)
 
(37,731
)
 
(15,970
)
Series A Preferred unit fair value adjustment

 
(4,596
)
 
(1,670
)
Series A Preferred unit in-kind distribution

 
(534
)
 

General partner unit in-kind distribution
(164
)
 
(207
)
 

Net loss attributable to Holdings
(4,258
)
 
(6,409
)
 

Net loss attributable to partners
$
(51,399
)
 
$
(36,659
)
 
$
(17,640
)
 
 
 
 
 
 
Earnings per unit and distributions declared:
 
 
 
 
 
Net loss allocated to limited partner common units
$
(24,790
)
 
$
(20,175
)
 
$
(8,683
)
Weighted average number of limited partner common units outstanding
26,781

 
21,642

 
12,225

Basic and diluted loss per common unit
$
(0.93
)
 
$
(0.93
)
 
$
(0.71
)
Distributions declared and paid per common unit
$
1.60

 
$
1.60

 
$
1.60

 
 
 
 
 
 
Net loss allocated to limited partner subordinated units
$
(11,300
)
 
$
(8,355
)
 
$
(8,638
)
Weighted average number of limited partner subordinated units outstanding
12,214

 
12,214

 
12,214

Basic and diluted loss per subordinated unit
$
(0.93
)
 
$
(0.68
)
 
$
(0.71
)
See accompanying notes to these consolidated financial statements.


77


SOUTHCROSS ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(In thousands)
 
Year Ended December 31,
 
2015
 
2014
 
2013
Net loss
$
(55,493
)
 
$
(37,731
)
 
$
(15,970
)
Other comprehensive income (loss):
 
 
 
 
 
Hedging losses reclassified to earnings and recognized in interest expense

 
221

 
415

Adjustment in fair value of derivatives

 
(11
)
 
(148
)
Total other comprehensive income

 
210

 
267

Comprehensive loss
$
(55,493
)
 
$
(37,521
)
 
$
(15,703
)
See accompanying notes to these consolidated financial statements.


78


SOUTHCROSS ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
 
Year Ended December 31,
 
2015
 
2014
 
2013
Cash flows from operating activities:
 
 
 
 
 
Net loss
$
(55,493
)
 
$
(37,731
)
 
$
(15,970
)
Adjustments to reconcile net loss to net cash provided by operating activities:

 

 
 
Depreciation and amortization
70,814

 
46,050

 
33,548

Unit-based compensation
4,573

 
10,074

 
2,186

Loss on extinguishment of debt

 
2,316

 

Amortization of deferred financing costs
3,494

 
2,005

 
1,287

Loss (gain) on sale of assets, net
416

 
365

 
(25
)
Unrealized loss (gain) on financial instruments
110

 
168

 
(120
)
Equity in losses of joint venture investments
13,452

 
6,496

 

Distribution from joint venture investment
500

 

 

Impairment of assets
7,067

 
1,556

 

Other, net
(82
)
 
65

 
130

Changes in operating assets and liabilities:
 
 
 
 
 
Trade accounts receivable, including affiliates
(3,069
)
 
(24,770
)
 
(6,675
)
Prepaid expenses and other current assets
(495
)
 
(5
)
 
(1,197
)
Other non-current assets
296

 
(29
)
 
215

Accounts payable and accrued liabilities
(24,559
)
 
35,658

 
1,411

Other liabilities, including affiliates
1,701

 
3,410

 
1,183

Net cash provided by operating activities
18,725

 
45,628

 
15,973

Cash flows from investing activities:
 
 
 
 
 
Capital expenditures
(108,698
)
 
(168,617
)
 
(93,863
)
Expenditures for assets subject to property damage claims, net of insurance proceeds and deductibles
78

 
2,706

 
(3,383
)
Proceeds from sale of assets
4,693

 
1,625

 
137

Investment contribution to joint venture investments
(8,910
)
 
(148
)
 

Consideration paid for Holdings' drop-down acquisition
(15,000
)
 

 

TexStar Rich Gas System acquisition from affiliate

 
(79,955
)
 

Other acquisitions

 
(44,038
)
 


Net cash used in investing activities
(127,837
)
 
(288,427
)
 
(97,109
)
Cash flows from financing activities:
 
 
 
 
 
Proceeds from issuance of common units, net

 
144,671

 

Borrowings under our credit facility
187,695

 
244,500

 
129,300

Borrowings under our term loan agreement

 
450,000

 

Repayments under our credit facility
(36,000
)
 
(481,800
)
 
(53,000
)
Repayments under our term loan agreement
(4,500
)
 
(2,250
)
 

Payments on capital lease obligations
(528
)
 
(599
)
 
(542
)
Financing costs
(698
)
 
(17,777
)
 
(2,139
)
Proceeds from issuance of Series A convertible preferred units, net of issuance costs

 

 
38,832

Contributions from general partner
1,301

 
9,967

 
800

Payments of distributions and distribution equivalent rights
(46,915
)
 
(52,645
)
 
(35,992
)
Assumption and repayment of debt in TexStar Rich Gas System Transaction

 
(100,000
)
 

Expenses paid by Holdings on behalf of Valley Wells' assets
17,858

 
50,564

 

Valley Wells operating expense cap adjustment
1,023

 

 

Other, net
(425
)
 
(3,532
)
 
(264
)
Net cash provided by financing activities
118,811

 
241,099

 
76,995

 
 
 
 
 
 
Net increase (decrease) in cash and cash equivalents
9,699

 
(1,700
)
 
(4,141
)
Cash and cash equivalents — Beginning of year
1,649

 
3,349

 
7,490

Cash and cash equivalents — End of year
$
11,348

 
$
1,649

 
$
3,349

See accompanying notes to these consolidated financial statements.


79


SOUTHCROSS ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL
(In thousands)
 
Partners' Capital
 
 
 
Limited Partners
 
General
Partner
 
Southcross Holdings' equity in contributed subsidiaries
 
Accumulated
Other
Comprehensive
Loss
 
 
 
Common
 
Class B Convertible
 
Subordinated
 
 
 
 
Total
BALANCE - December 31, 2012
$
194,364

 
$

 
$
125,952

 
$
6,628

 
$

 
$
(477
)
 
$
326,467

Net loss
(7,829
)
 

 
(7,822
)
 
(319
)
 

 

 
(15,970
)
Unit-based compensation on long-term incentive plan
1,601

 

 

 

 

 

 
1,601

Series A convertible preferred unit in-kind distribution and fair value adjustments
(838
)
 

 
(799
)
 
(33
)
 

 

 
(1,670
)
Contributions from general partner

 

 

 
800

 

 

 
800

Cash distributions paid
(17,597
)
 

 
(17,589
)
 
(742
)
 

 

 
(35,928
)
Accrued distribution equivalent rights on long-term incentive plan
(279
)
 

 

 

 

 

 
(279
)
Tax withholdings on unit-based compensation vested units
(264
)
 

 

 

 

 

 
(264
)
General partner unit in-kind distribution
(17
)
 

 
(16
)
 
33

 

 

 

Net effect of cash flow hedges

 

 

 

 

 
267

 
267

BALANCE - December 31, 2013
$
169,141

 
$

 
$
99,726

 
$
6,367

 
$

 
$
(210
)
 
$
275,024

Net loss
(15,155
)
 
(7,436
)
 
(8,105
)
 
(626
)
 
(6,409
)
 

 
(37,731
)
Issuance of common units, net
144,671

 

 

 

 

 

 
144,671

Issuance of Class B Convertible units, net

 
324,413

 

 

 

 

 
324,413

Consideration paid in excess of the net book value of the TexStar Rich Gas System
(45,420
)
 
(27,925
)
 
(23,308
)
 
(1,972
)
 

 

 
(98,625
)
Class B Convertible unit in-kind distribution
(6,209
)
 
9,610

 
(3,193
)
 
(208
)
 

 

 

Unit-based compensation on long-term incentive plan
9,947

 

 

 

 

 

 
9,947

Series A convertible preferred conversion into common units
45,624

 

 

 

 

 

 
45,624

Series A convertible preferred unit in-kind distribution and fair value adjustments
(3,126
)
 

 
(1,897
)
 
(107
)
 

 

 
(5,130
)
Contributions from general partner
809

 
171

 
345

 
9,991

 

 

 
11,316

Cash distributions and distribution equivalent rights paid
(36,706
)
 

 
(14,657
)
 
(1,282
)
 

 

 
(52,645
)
Accrued distribution equivalent rights on long-term incentive plan
(167
)
 

 

 

 

 

 
(167
)
Tax withholdings on unit-based compensation vested units
(3,532
)
 

 

 

 

 

 
(3,532
)
General partner unit in-kind distribution
(142
)
 

 
(80
)
 
222

 

 

 

Net effect of cash flow hedges

 

 

 

 

 
210

 
210

Consolidation of Valley Wells' net assets

 

 

 

 
33,165

 

 
33,165

Expenses paid by Holdings on behalf of Valley Wells' assets

 

 

 

 
50,564

 

 
50,564

BALANCE - December 31, 2014
$
259,735

 
$
298,833

 
$
48,831

 
$
12,385

 
$
77,320

 
$

 
$
697,104

Net loss
(24,730
)
 
(14,225
)
 
(11,256
)
 
(1,024
)
 
(4,258
)
 

 
(55,493
)
Contributions from general partner

 

 

 
1,301

 

 

 
1,301

Class B Convertible unit in-kind distribution
(5,340
)
 
8,059

 
(2,557
)
 
(162
)
 

 

 

Unit-based compensation on long-term incentive plan
4,443

 

 

 

 

 

 
4,443

Cash distributions and distribution equivalent rights paid
(41,733
)
 

 
(3,432
)
 
(1,750
)
 

 

 
(46,915
)
Accrued distribution equivalent rights on long-term incentive plan
(718
)
 

 

 

 

 

 
(718
)
Tax withholdings on unit-based compensation vested units
(425
)
 

 

 

 

 

 
(425
)
General partner unit in-kind distribution
(112
)
 

 
(53
)
 
165

 

 

 

Valley Wells' operating expense cap adjustments
2,670

 

 

 

 

 

 
2,670


80


 
Partners' Capital
 
 
 
Limited Partners
 
General
Partner
 
Southcross Holdings' equity in contributed subsidiaries
 
Accumulated
Other
Comprehensive
Loss
 
 
 
Common
 
Class B Convertible
 
Subordinated
 
 
 
 
Total
Purchase of assets in Holdings drop-down acquisition
62,640

 

 

 

 
(77,640
)
 

 
(15,000
)
Contribution of NGL pipelines in Holdings drop-down acquisition

 

 

 

 
15,000

 

 
15,000

Net assets contributed in Holdings drop-down acquisition in excess of consideration paid
14,806

 
7,929

 
6,387

 
594

 
(29,716
)
 

 

Expenses paid by Holdings on behalf of Valley Wells' assets

 

 

 

 
17,858

 

 
17,858

Interest related to receivable due from Holdings

 

 

 
75

 

 

 
75

Net liabilities assumed by Holdings in Holdings drop-down acquisition

 

 

 

 
1,436

 

 
1,436

BALANCE - December 31, 2015
$
271,236

 
$
300,596

 
$
37,920

 
$
11,584

 
$

 
$

 
$
621,336

See accompanying notes to these consolidated financial statements.


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1. ORGANIZATION, DESCRIPTION OF BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
Organization
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.
On August 4, 2014, Southcross Energy LLC and TexStar Midstream Services, LP, a Texas limited partnership (“TexStar”), combined pursuant to a contribution agreement in which Southcross Holdings LP, a Delaware limited partnership (“Holdings”), was formed (the “Holdings Transaction”). As a result of the Holdings Transaction, Holdings indirectly owns 100% of Southcross Energy Partners GP, LLC, a Delaware limited liability company and our General Partner (“General Partner”) (and therefore controls us), all of our subordinated units and a portion of our common units. Our General Partner owns an approximate 2.0% interest in us and all of our incentive distribution rights.
Following the emergence of Holdings from its Chapter 11 reorganization proceeding on April 13, 2016 (as discussed below), EIG Global Energy Partners, LLC (“EIG”) and Tailwater Capital LLC (“Tailwater”) (collectively, the “Sponsors”) each indirectly own approximately one-third of Holdings, and a group of consolidated lenders under Holdings' revolving credit facility and term loan own the remaining one-third equity interest, which previously was owned by Charlesbank Capital Partners, LLC.
Contemporaneously with the closing of the Holdings Transaction, TexStar contributed to us certain gathering and processing assets (the “TexStar Rich Gas System”), which were owned by TexStar (the “TexStar Rich Gas System Transaction”). As a result of the TexStar Rich Gas System Transaction, Holdings indirectly owns all of our Class B Convertible Units (the "Class B Convertible Units"). For additional details regarding the Holdings Transaction and the TexStar Rich Gas System Transaction, see Notes 1, 3, 8, 10, 12 and 15.
On May 7, 2015, we acquired gathering, treating, compression and transportation assets (the “2015 Holdings Acquisition”) from Holdings and its subsidiaries consisting of the Valley Wells sour gas gathering and treating system (the "Valley Wells System"), compression assets that are part of the Valley Wells and Lancaster gathering and treating systems (the "Compression Assets") and two NGL pipelines.
Description of Business
We are a master limited partnership, headquartered in Dallas, Texas, 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 four gas processing plants, two fractionation facilities and approximately 3,138 miles of pipeline.
Segments
Our chief operating decision-maker is our Chief Executive Officer who reviews financial information presented on a consolidated basis in order to assess our performance and make decisions about resource allocations. There are no segment managers who are held accountable by the chief operating decision-maker, or anyone else, for operations, operating results and planning for levels or components below the consolidated unit level. Accordingly, we have determined that we have one reportable segment.
Basis of Presentation
The accompanying consolidated financial statements and related notes present the consolidated balance sheets as of December 31, 2015 and 2014 and the consolidated statements of operations, comprehensive income (loss), cash flows and changes in partners' capital for the years ended December 31, 2015, 2014 and 2013 (See Note 2).
The consolidated financial statements reflect the assets acquired and liabilities assumed and the related operating results associated with (i) the Onyx pipelines acquisition on March 6, 2014, (ii) the TexStar Rich Gas System Transaction and the 2015 Holdings Acquisition on August 4, 2014, (iii) and the Texoz acquisition on November 21, 2014. See Note 3.

As a result of the Holdings Transaction, Holdings acquired a controlling equity interest in the Partnership, which was

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accounted for under the acquisition method of accounting in the consolidated financial statements of Holdings, whereby Holdings recorded the Partnership’s assets acquired and liabilities assumed at fair value. However, because less than 80% of the equity interests in the Partnership were acquired, push down accounting of Holdings' basis in the Partnership was prohibited in our consolidated financial statements.

Additionally, because the TexStar Rich Gas System was owned by TexStar, the Partnership recorded the TexStar Rich Gas System at TexStar’s historical cost. Thus, the difference between consideration paid and the TexStar Rich Gas System’s historical cost (net book value) at August 4, 2014, the date on which the Holdings Transaction and the TexStar Rich Gas System Transaction closed, was recorded as a reduction to partners’ capital. Management concluded that the Partnership was the predecessor for accounting purposes for periods prior to August 4, 2014. 

We recognized the 2015 Holdings Acquisition at Holdings’ historical cost because the acquisition was executed by entities under common control. Thus, the difference between consideration paid and Holdings’ historical cost (net book value) at May 7, 2015, the date on which the 2015 Holdings Acquisition closed, was recorded as a reduction to partners’ capital. Due to the common control aspect, the 2015 Holdings Acquisition was accounted for by the Partnership on an “as if pooled” basis for the periods during which common control existed which began on August 4, 2014. See Note 3.
The accompanying consolidated financial statements were prepared in accordance with accounting principles generally accepted in the U.S. ("GAAP") and in accordance with the rules and regulations of the U.S. Securities and Exchange Commission ("SEC"). Our consolidated financial statements include the accounts of Southcross and its 100% owned subsidiaries. We eliminate all intercompany balances and transactions in preparing consolidated financial statements.
We evaluate events that occur after the balance sheet date, but before the financial statements are issued, for potential recognition or disclosure. Based on the evaluation, we determined that there were no material subsequent events for recognition or disclosure other than those disclosed in this report.
Principles of Consolidation
We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. We do not have ownership in any consolidated variable interest entities.
Use of Estimates
The preparation of the consolidated financial statements in conformity with GAAP requires management to make various estimates and assumptions that may affect the amounts of assets and liabilities, disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. Actual results may differ from those estimates.
Significant Accounting Policies
Revenue Recognition
Using the revenue recognition criteria of persuasive evidence of an exchange arrangement exists, delivery has occurred or services have been rendered and the price is fixed or determinable, we record natural gas and NGL revenue in the period when the physical product is delivered to the customer and in an amount based on the pricing terms of an executed contract. Our transportation, compression, processing, fractionation and other revenue is recognized in the period when the service is provided and includes our fee-based service revenue. In addition, collectability is evaluated on a customer-by-customer basis. New customers are subject to a credit review process, which evaluates the customers' financial position and their ability to pay.
Our sale and purchase arrangements are primarily accounted for on a gross basis in the statements of operations. These transactions are contractual arrangements that establish the terms of the purchase of natural gas or NGLs at a specified location and the sale of natural gas or NGLs at a different location on the same or on another specified date. These transactions require physical delivery and transfer of the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk.
We derive revenue in our business from the following types of 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.

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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 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.
Certain of our gathering and processing agreements provide for quarterly and annual minimum volume commitment ("MVC"). Under these MVCs, our customers agree to ship and/or process a minimum volume of production on our gathering systems or to pay a minimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to us at the end of the contracted measurement period if its actual throughput volumes are less than its MVC for that period. Certain customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent measurement periods to the extent that such customer's throughput volumes in a subsequent contracted measurement period exceed its MVC for that contracted measurement period.
We recognize customer billings for obligations under their MVCs as revenue when the obligations are billable under the contract and the customer does not have the right to utilize shortfall payments to offset gathering fees in excess of its MVCs in subsequent periods.
We record customer billings for obligations under their MVCs as deferred revenue when the customer has the right to utilize shortfall payments to offset gathering or processing fees in subsequent periods. We recognize deferred revenue under these arrangements in revenue once all contingencies or potential performance obligations associated with the related volumes have either (i) been satisfied through the gathering or processing of future excess volumes of natural gas, or (ii) expired (or lapsed) through the passage of time pursuant to the terms of the applicable natural gas gathering agreement.
We classify deferred revenue as a current liability for arrangements where the expiration of a customer's right to utilize shortfall payments is 12 months or less.
Long-Lived Assets
Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead and the cost of financing construction. Costs associated with obtaining rights of way agreements and easements to facilitate the building and maintenance of new pipelines are capitalized and depreciated over the life of the associated pipeline. We capitalize major units of property replacements or improvements and expense minor items. We use the straight-line method to depreciate property, plant and equipment over the estimated useful lives of the assets. We depreciate leasehold improvements and capital lease assets over the shorter of the life of the asset or the life of the lease. Maintenance and repairs are charged directly to expense as incurred, with the exception of substantial compression overhaul costs, which are capitalized and depreciated over the life of the overhaul.
Our intangible assets consist of acquired long-term supply and gas gathering contracts. We amortize these contracts on a straight-line basis over the 30-year expected useful lives of the contracts.
Impairment of Long-Lived Assets
We evaluate our long-lived assets, which include finite-lived intangible assets, for impairment when events or circumstances indicate that their carrying values may not be recoverable. These events include, but are not limited to, market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, we evaluate the recoverability of our carrying value based on the long-lived asset's ability to generate future cash flows on an undiscounted basis. If the undiscounted cash flows are not sufficient to recover the long-lived asset's carrying value, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying values of the asset downward, if

84


necessary, to their estimated fair value. Our fair value estimates are generally based on assumptions market participants would use, including market data obtained through the sales process or an analysis of expected discounted cash flows. With the recent decline in commodity prices negatively affecting the level of natural gas and crude oil production, we concluded that a triggering event had occurred which required we test for impairment of our assets. Our undiscounted cash flows were in excess of our long-lived assets' carrying value. However, during the year ended December 31, 2015, we recorded $7.1 million of impairment costs related primarily to a write-down of a spare turbine. During the year ended December 31, 2014, we recorded $1.6 million of impairment costs primarily related to right of way costs on a canceled project. We did not record any impairments during the year ended December 31, 2013.
Cash and Cash Equivalents
We consider all short-term investments with an original maturity of three months or less to be cash equivalents. At December 31, 2015 and 2014, except for amounts held in bank accounts to cover current payables, all of our cash equivalents were invested in short-term money market accounts and overnight sweep accounts.
Allowance for Doubtful Accounts
In evaluating the collectability of our accounts receivable, we perform credit evaluations of our new customers and adjust payment terms based upon payment history and each customer's current creditworthiness, as determined by our review of such customer's credit information. We extend credit on an unsecured basis to many of our customers. In the event of a bankruptcy filing by a customer, we will determine if we will legally be able to collect any of the outstanding balance as a secured or unsecured creditor, and based on this determination we will reserve against part, or all, of the outstanding balance. We recorded an allowance for uncollectible accounts receivable of $0.1 million at December 31, 2015. We recorded no allowance for uncollectible accounts receivable at December 31, 2014.
Asset Retirement Obligations
We evaluate whether any future asset retirement obligations ("AROs") exist and estimate the costs for such AROs for certain future events. An ARO will be recorded in the periods where we can reasonably determine the settlement dates or the period in which the expense is incurred, and an estimated cost of the retirement obligation. Generally we do not have the intention of discontinuing the use of any significant assets or have a legal obligation to do so. Therefore, in these situations we do not have sufficient information to reasonably estimate any future AROs. No AROs were recorded for the years ended December 31, 2015 and 2014.
Environmental Costs and Other Contingencies
We recognize liabilities for environmental and other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and no specific amount in that range is more likely than any other, the low end of the range is accrued. In July 2015, we paid a $0.1 million fine to OSHA related to the fire at our Gregory facility in January 2015. No amounts were recorded as of December 31, 2014.
Fair Value of Financial Instruments
Accounting guidance requires the disclosure of the fair value of all financial instruments that are not otherwise recorded at fair value in the financial statements. At December 31, 2015 and 2014, financial instruments recorded at contractual amounts that approximate fair value include certain funds on deposit, accounts receivable, other receivables and accounts payable and accrued liabilities. The fair values of such items are not materially sensitive to shifts in market interest rates because of the short term to maturity of these instruments (See Note 6).

As of December 31, 2015 and 2014, the fair value of the debt funded through our credit facilities approximates its carrying amount primarily due to the variable nature of the interest rate of the instrument and is considered a Level 2 fair value measurement. (See Note 6).
Derivative Instruments
In our normal course of business, we enter into month-ahead commodity swap contracts in order to hedge economically our exposure to certain intra-month natural gas index pricing risk. We manage our interest rate risk through interest rate swaps and interest rate caps (See Note 6).
Derivative financial instruments are recorded in the consolidated balance sheets at fair value, except for derivative

85


contracts that we qualify for and for which we have elected the normal purchase or normal sale exceptions, which are not reflected in the consolidated balance sheets or statements of operations prior to accrual of the settlement. We present our derivative assets and liabilities on a net basis.
If certain criteria are met, a derivative financial instrument may be designated as a fair value hedge or cash flow hedge. The changes in fair value of cash flow hedges are deferred in accumulated other comprehensive loss, net of tax, to the extent the contracts are, or have been, effective as hedges, until the forecasted transactions impact earnings. The ineffective portion of changes in fair value of cash flow hedges is recognized immediately into earnings.
On an ongoing basis, a derivative instrument designated as a cash flow hedge must be highly effective in offsetting changes in cash flows of the hedged item. If it is determined that the derivative instrument is not highly effective as a hedge, hedge accounting will be discontinued prospectively. Changes in fair value of the associated hedging instrument are then recognized immediately in earnings for the remainder of the contract term unless a new hedging relationship is designated. The assessment of effectiveness excludes counterparty default risk and our own nonperformance risk. The effect of these valuation adjustments was immaterial for the year ended December 31, 2014.
Derivative financial instruments designated as cash flow hedges must have a high correlation between price movements in the derivative and the hedged item. If and when an acceptable level of correlation no longer exists, hedge accounting ceases and changes in fair value are recognized in our statements of operations. If it becomes probable that a forecasted transaction will not occur, we immediately recognize the related deferred gains or losses in our statements of operations. Changes in fair value of the associated hedging instrument are then recognized immediately in earnings for the remainder of the contract term unless a new hedging relationship is designated.
In March 2012, we entered into an interest rate swap to reduce the risks with respect to the variability of the interest rates under our Previous Credit Facility. In February 2014, we discontinued cash flow hedge accounting on a prospective basis as a result of the repayment of borrowings under our Previous Credit Facility (See Note 8). With the exception of this interest rate swap, we did not have any other derivative financial instruments designated as fair value or cash flow hedges for accounting purposes during the years ended December 31, 2015 and 2014.
For our derivative financial instruments that have not been designated as cash flow hedges for accounting purposes, changes in such instruments' fair values are recognized immediately in earnings. We do not hold or issue financial instruments or derivative financial instruments for trading purposes.
Unit-Based Compensation
Unit-based awards which settle in common units are classified as equity and are recognized in the financial statements over the vesting period at their grant date fair value. Unit-based awards which settle in cash are classified as liabilities and remeasured at every balance sheet date through settlement, such that the vested portion of the liability is adjusted to reflect its revised fair value through compensation expense. Currently, all awards granted under the Amended and Restated 2012 Long-Term Incentive Plan (the “LTIP”) will be settled in common units. Compensation expense associated with unit-based awards, adjusted for forfeitures, is recognized evenly from the date of the grant over the vesting period within operations and maintenance and general and administrative expense on our consolidated statements of operations.
Income Taxes
No provision for federal or state income taxes, except as noted below, is included in our statements of operations as such income is taxable directly to our partners. Each partner is responsible for its share of federal and state income tax. Net earnings for financial statement purposes may differ significantly from taxable income reportable to each partner as a result of differences between the tax basis and financial reporting basis of assets and liabilities.
We are subject to the Texas margin tax which qualifies as an income tax under GAAP that requires us to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis. Our current tax liability will be assessed based on the gross revenue apportioned to Texas. For the years ended December 31, 2015 and 2014, there were no material temporary differences.
On September 13, 2013, the U.S. Department of the Treasury and IRS issued the final and re-proposed tangible property regulations effective for tax years beginning January 1, 2014. The provisions of these regulations had no impact our financial statements.
Uncertain Tax Positions
We evaluate the uncertainty in tax positions taken or expected to be taken in the course of preparing our consolidated

86


financial statements to determine whether the tax positions are more likely than not of being sustained by the applicable tax authority. We believe that there are no uncertain tax positions and that no provision for income tax is required for these consolidated financial statements.
Earnings per Unit
Net loss per unit is calculated under the two-class method of computing earnings per unit when participating or multiple classes of securities exist. Under this method, undistributed earnings or losses for a period are allocated based on the contractual rights of each security to share in those earnings as if all of the earnings for the period had been distributed.
Basic net loss per unit excludes dilution and is computed by dividing net loss attributable to limited partner common units by the weighted average number of limited partner common units outstanding during the period. Paid-in kind distributions and valuation adjustments to maximum redemption value of the Series A convertible preferred units (which converted to common units on August 4, 2014) are excluded from income available to common units in the calculation of basic earnings per unit. Dilutive net loss per unit reflects potential dilution from the potential issuance of limited partner common units. Dilutive net loss per unit is calculated using the treasury stock method. It is computed by dividing net loss attributable to limited partner common units by the weighted average number of limited partner common units outstanding during the period increased by the number of additional limited partner common units that would have been outstanding if the dilutive potential limited partner common units had been issued.
Investments in Joint Ventures
We hold equity interests in three joint venture entities as a result of the TexStar Rich Gas System Transaction. We own a 50% or less equity interest in each of the three entities. The joint venture arrangements give equal management rights with no single investor having unilateral control. Each party sharing joint control must consent to the ventures’ operating, investing and financing decisions. Therefore, because we do not have controlling financial interests, but do have significant influence, we use the equity method of accounting for investments in joint ventures. We recognize our share of the earnings and losses in the joint ventures pursuant to the terms of the applicable limited liability agreements governing such joint ventures, which provide for earnings and losses generally to be allocated based upon each member’s respective ownership interest in the joint ventures. We record our proportionate share of the joint ventures’ net income/loss as equity in income/losses of joint venture investments in the statements of operations. We evaluate investments in joint ventures for impairment when factors indicate that a decrease in the value of the investment has occurred that is not temporary. See Note 15.
Recent Accounting Pronouncements
Accounting standard-setting organizations frequently issue new or revised accounting pronouncements. We review and evaluate new pronouncements and existing pronouncements below to determine their impact, if any, on our consolidated financial statements. We are evaluating the impact of each pronouncement on our consolidated financial statements.
In 2014, a comprehensive new revenue recognition standard that will supersede substantially all existing revenue recognition guidance under GAAP was issued. The standard's core principle is that a company will recognize revenue when it transfers promised goods or services to customers and in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In July 2015, the Financial Accounting Standards Board ("FASB") voted to defer the new revenue recognition standard. The standard is currently set to be effective in the first quarter of 2018.

In 2014, a new going concern standard was issued that will update existing going concern guidance under GAAP. The standard’s new guidance relates to defining management’s responsibility to evaluate whether there is substantial doubt about an organization’s ability to continue as a going concern. Related disclosure in the notes to the consolidated financial statements will be required surrounding whether it is probable that the entity will not be able to meet its obligations as they become due within one year after the date that financial statements are issued. We are required to adopt this standard for the fiscal year ended December 31, 2016.

In February 2015, the FASB issued a pronouncement that amended current consolidation guidance with regard to variable interest entities and voting interest entities. This standard will become effective beginning in 2016.

In April 2015, the FASB issued a pronouncement simplifying the presentation of debt issuance costs. The amendment requires that debt issuance costs related to a recognized debt liability be presented on the balance sheet as a reduction to the carrying amount of that debt liability, consistent with the presentation for debt discounts. The recognition and measurement guidance for debt issuance costs is not affected by the amendments. In August 2015, the FASB further clarified that the SEC staff would not object to a similar capitalization and amortization of deferred issuance costs for line of credit arrangements.

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This standard will become effective beginning in 2016, however we have elected to early adopt this standard in this report. See Note 8.

In April 2015, the FASB issued a pronouncement that specifies how to calculate historical earnings per unit for a master limited partnership with retrospectively adjusted financial statements subsequent to a drop-down acquisition. The amendments specify that for purposes of calculating historical earnings per unit under the two-class method, the earnings or losses of a transferred business before the date of a drop-down acquisition are to be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners would not change as a result of the drop-down acquisition. Qualitative disclosures about how the rights to the earnings or losses differ before and after the drop-down acquisition occurs for purposes of computing earnings per unit under the two-class method are also required. This standard will become effective beginning in 2016; however, we have elected to early adopt this standard in this report and have retrospectively adjusted our prior period balances related to this standard in this report. See Note 5.

In September 2015, the FASB issued a pronouncement simplifying the recognition of provisional amounts that are identified during the measurement period of an acquisition. The amendments require an entity to present separately on the face of the income statement or disclose in the notes to the financial statements the portion of the amount recorded in the current period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. This standard will become effective beginning in 2016.

In February 2016, the FASB issued a pronouncement amending disclosure and presentation requirements for lessees and lessors to better reflect the recognition of assets and liabilities that arise from leases. The pronouncement states that a lessee should recognize a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term on the face of the balance sheet. When measuring assets and liabilities arising from a lease, a lessee (and a lessor) should include payments to be made in optional periods only if the lessee is reasonably certain to exercise an option to extend the lease or not to exercise an option to terminate the lease. Similarly, optional payments to purchase the underlying asset should be included in the measurement of lease assets and lease liabilities only if the lessee is reasonably certain to exercise that purchase option. In addition, also consistent with the previous leases guidance, a lessee (and a lessor) should exclude most variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. This standard will become effective beginning in 2019.

2. LIQUIDITY CONSIDERATIONS
Our business exposes us to certain risks associated with the development of natural gas, crude oil and natural gas liquids which could have a material adverse effect on our cash flows, operations and liquidity, including, but not limited to:
fluctuations in the volume of natural gas we gather, process, treat, compress and transport and the volume of NGLs we fractionate and transport;
fluctuations in drilling and development activity in the geographic locations in which we operate;
credit risk associated with all customers; and
the level of production of, and the demand for, crude oil, natural gas and NGLs and the market prices of crude oil, natural gas and NGLs.
Beginning in the second half of 2014 and continuing through the issuance of this annual report, commodity prices have experienced increased volatility. In particular, natural gas, crude oil and NGL prices have decreased significantly. Our future cash flow will be materially adversely affected if prolonged pricing deterioration continues for the commodities we sell or if a material reduction in drilling for oil or natural gas continues in the geographic areas in which we operate, including the Eagle Ford Shale region.
The majority of our revenue is derived from fixed-fee contracts, which have limited direct exposure to commodity price levels since 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 being paid based on the value of the underlying natural gas or NGLs. In addition, a percentage of our contract portfolio contains minimum volume commitment arrangements. The majority of our volumes are dependent upon the level of producer drilling activity.
After considering these uncertainties, and in developing our annual budget for 2016, our forecast indicates future shortfalls in the amount of consolidated EBITDA (as defined in the Third Amended and Restated Revolving Credit Agreement with Wilmington Trust, National Association, as Administrative Agent, UBS Securities LLC and Barclays Bank PLC, as Co-Syndication Agents, JPMorgan Chase Bank, N.A., as Documentation Agent, and a syndicate of lenders (the “Third A&R

88


Revolving Credit Agreement”), as amended in May 2015) necessary to remain in compliance with the consolidated total leverage ratio of our Financial Covenants (as defined in Note 8) in our Credit Facility for the remainder of 2016. As discussed in further detail in Note 8, we have the right to cure such a Financial Covenant Default (as defined in Note 8) by either our Sponsors or Holdings purchasing equity interests in or making capital contributions (an equity cure) resulting in, among other things, proceeds that, if added to consolidated EBITDA, would result in us satisfying the Financial Covenants. Once such an equity cure is made, it is included in our consolidated EBITDA calculation in any rolling twelve month period that includes the quarter that was cured. Should there be an event of default under the Credit Facility, and such default is not cured, we would also experience a cross default under our Term Loan Agreement (defined in Note 8) and all of our debt would become due and payable to our lenders.
As of December 31, 2015, we were not in compliance with the consolidated total leverage ratio of our Financial Covenants absent an equity cure of $14.9 million. On March 30, 2016, we funded this equity cure with the remaining $3.0 million of the contractual $13.0 million non-cash equity cure credit amount from our Credit Agreement Amendment (as defined in Note 8) and $11.9 million of the $50 million equity commitment from Holdings, discussed below. We used $10.0 million of the contractual $13.0 million non-cash equity cure credit amount from our Credit Agreement Amendment to fund equity cures as of June 30, 2015 and September 30, 2015 in order to stay in compliance with the consolidated total leverage ratio of our Financial Covenants. We anticipate funding additional equity cures needed to maintain compliance with our Financial Covenants through the end of 2016 with the additional equity commitment from Holdings.
In connection with Holdings' Chapter 11 reorganization, Holdings has committed to contribute up to $50 million to us (the “Contribution Amount”) to ensure we have sufficient liquidity to comply with applicable Financial Covenants through the quarter ended December 31, 2016. In exchange for the Contribution Amount, we will issue Holdings a number of our common units representing limited partner interests equal to, subject to certain exceptions, (i) the applicable Contribution Amount divided by (ii) a common unit reference price (“Reference Price”) equal to the volume weighted daily average price of the common units on the New York Stock Exchange (“VWAP”) calculated for a period of 15 trading days ending two trading days prior to the contribution by Holdings. Notwithstanding the VWAP calculation, the Reference Price will be no less than $0.89 per common unit and no greater than $1.48 per common unit (the “Range”), and if the VWAP is within the Range for a period of 15 trading days, the first of which is the tenth trading day following March 28, 2016, the date of the announcement, such VWAP will be the Reference Price for all common units issued in exchange for the Contribution Amount. The $11.9 million in cash necessary to cure the non-compliance in the fourth quarter of 2015 was contributed to us under the terms of the debtor in possession (“DIP”) arrangement agreed to in the Holdings' Chapter 11 reorganization proceedings discussed in Note 1. In accordance with the requirements above and the amount funded for this equity cure, Holdings will be issued between 8.0 million and 13.4 million common units. However, the number of units to be issued to Holdings in exchange for this contribution has yet to be determined due to the required number of days to calculate the VWAP not being reached as of the date of the issuance of these financial statements.
On January 7, 2016, in response to our need for additional liquidity, we issued at par Senior Unsecured PIK Notes in the aggregate principal amount of $14.0 million (the "PIK Notes") to affiliates of EIG and Tailwater (collectively, the "PIK Lenders"), that bear interest at a rate of 7% per annum, payable in cash or, at the option of the Partnership, in-kind. The PIK Notes will mature on January 7, 2017. Subsequent to the balance sheet date, but prior to the issuance of our annual report, and in accordance with the POR, the PIK Notes and the related interest were repaid in full.
In addition, subsequent to the balance sheet date, but prior to the issuance of our annual report, the receivable due from Holdings of $43.0 million was brought current. Therefore, these financial statements have been presented as if we will continue as a going concern. See Note 8.
As of December 31, 2015, after using an equity cure of $14.9 million to stay in compliance with the consolidated total leverage ratio of our Financial Covenants, we were in compliance with the covenants set forth in the Senior Credit Facilities. Additionally, the annual financial statements of the Partnership were not filed timely as required under the Senior Credit Facilities and the issuance of the financial statements on April 14, 2016 cures such potential event of default.

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3. ACQUISITIONS
TexStar Rich Gas System Transaction. On August 4, 2014, contemporaneously with the closing of the Holdings Transaction, TexStar contributed to us certain gathering and processing assets (the “TexStar Rich Gas System”), through a contribution of TexStar’s equity interest in the entities that own the TexStar Rich Gas System (the “Contribution”) to us. In exchange for the Contribution, we paid $80 million in cash, assumed $100 million of debt (which was immediately repaid through our Term Loan Agreement (as defined in Note 8)) and issued 14,633,000 Class B Convertible Units (the “Class B Convertible Units”). The TexStar Rich Gas System consists of a cryogenic processing plant, located in Bee County, Texas, and joint venture ownership in natural gas gathering and residue pipelines across the core producing areas extending from Dimmit to Karnes Counties, Texas in the liquids-rich window of the Eagle Ford Shale region. These pipelines are operated under split-capacity arrangements within joint venture arrangements with Targa Pipeline Partners, L.P. ("Targa").
The amount of the consideration paid over TexStar’s net book value of the assets received and liabilities assumed of the TexStar Rich Gas System is recorded as a reduction to partners’ capital as summarized as follows (in thousands):
Consideration paid(1)
 
$
404,414

Current assets
 
$
1,295

Property, plant and equipment, net
 
255,220

Investments in joint ventures(2)
 
152,050

Total assets contributed
 
408,565

Total liabilities assumed(3)
 
(102,776
)
Net identifiable assets contributed
 
$
305,789

Consideration paid in excess of net assets contributed
 
$
98,625

Allocation of reduction to partners' capital:
 
 
Common limited partner interest

$
45,420

Class B Convertible limited partner interest

27,925

Subordinated limited partner interest

23,308

General Partner interest

1,972

Total reduction to partners' capital
 
$
98,625

____________________________________________________________________________
(1) This amount was calculated as follows: $80 million of cash plus 14,633,000 Class B Convertible Units at an issue price of $22.17, the closing price of the Partnership’s common units on August 4, 2014.
(2) Significant assets acquired through the TexStar Rich Gas System Transaction include equity interests in three joint ventures. See Note 15.
(3) This amount includes $100 million of debt assumed.
  
Onyx Pipelines Acquisition. On March 6, 2014, our subsidiary, Southcross Nueces Pipelines LLC, acquired natural gas pipelines near Corpus Christi, Texas and contracts related to these pipelines from Onyx Midstream, LP and Onyx Pipeline Company (collectively, “Onyx”) for $38.6 million in cash, net of certain adjustments as provided in the purchase agreement.

The pipelines transport natural gas to two power plants in Nueces County, Texas under fixed-fee contracts that extend through 2029 and include an option to extend the agreements by an additional term of up to ten years. The contracts were renegotiated in connection with the acquisition; therefore, we consider these contracts to be assumed at fair market value.

The fair values of the property, plant and equipment are based upon assumptions related to expected future cash flows, discount rates and asset lives using currently available information. We utilized a mix of the cost, income and market approaches to determine the estimated fair values of such assets. The fair value measurements and models have been classified as non-recurring Level 3 measurements.
We performed our assessment of the fair value of the assets acquired and liabilities assumed, and the consideration given was considered equal to the fair value of net assets acquired. As a result, no goodwill was recorded. The assessment was finalized during the second quarter of 2014 and there were no changes to the preliminary balances previously recorded.

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The fair value of the assets acquired and liabilities assumed related to the Onyx purchase price was as follows (in thousands):
Purchase Price—Cash
$
38,636

Current assets
$
730

Property, plant and equipment
39,413

Total assets acquired
40,143

Current liabilities assumed
(1,407
)
Other liabilities assumed
(100
)
Net identifiable assets acquired
$
38,636

Unaudited Pro Forma Financial Information for Onyx Pipelines Acquisition. The following unaudited pro forma financial information for the year ended December 31, 2013 and the year ended December 31, 2014 assumes that the acquisition of pipelines from Onyx occurred on January 1, 2013 and includes adjustments for income from operations, including depreciation and amortization, as well as the effects of financing the transaction (in thousands, except unit information):
 
 
Year Ended December 31,
 
 
2014
 
2013
Total revenue
 
$
843,376

 
$
639,104

Net loss
 
(31,400
)
 
(18,306
)
Net loss attributable to common unitholders
 
(20,211
)
 
(9,934
)
Net loss per common unit (basic and diluted)
 
(0.85
)
 
(0.68
)
Net loss attributable to subordinated unitholders
 
(8,373
)
 
(9,678
)
Net loss per subordinated unit (basic and diluted)
 
(0.69
)
 
(0.79
)
The unaudited pro forma information is not necessarily indicative of what our statements of operations would have been if the transaction had occurred on that date, or what the financial position or results from operations will be for any future periods. For the year ended December 31, 2014, the Onyx pipelines business contributed $4.2 million in revenues and $1.3 million in net income to our statements of operations.
Texoz Acquisition. On November 21, 2014, we completed the acquisition of a natural gas gathering system in McMullen County, Texas (the “Texoz System”) from LT Gathering, LLC for $5.4 million in cash, net of certain adjustments as provided in the purchase agreement (the “Texoz Acquisition”). The Texoz System consists of eight miles of gathering pipelines within two miles of our existing rich gas pipeline network and services customers under acreage dedication contracts. Due to the immaterial amount of this transaction, no pro-forma financial information was disclosed in this report.
Holdings Drop-Down Acquisition. On May 7, 2015, we completed the 2015 Holdings Acquisition pursuant to a Purchase, Sale and Contribution Agreement among Holdings, TexStar Midstream Utility, LP, Frio LaSalle Pipeline, LP (“Frio”), us and certain of our subsidiaries. The acquired assets consist of the Valley Wells System, Compression Assets and two NGL pipelines that were under construction at the time of the transaction (and that are now operational). Total consideration for the assets was $15.0 million in cash and 4.5 million new common units, valued as of the date of closing, issued to Holdings equating to $77.6 million. We also assumed the remaining capital expenditures for the completion of the NGL pipelines that were under construction.

The Valley Wells System is located in the Eagle Ford Shale region, in LaSalle County, Texas. The system has sour gas treating capacity of approximately 100 MMcf/d and is supported by a 60 MMcf/d minimum volume commitment from Holdings for gathering and treating services, while Holdings has producer contracts with minimum volume commitments totaling 35 MMcf/d behind the system. The system is connected to our rich gas system for transport and processing. The assets acquired in the 2015 Holdings Acquisition includes over 50,000 horsepower of compression capability that serve both the Valley Wells and Lancaster gathering systems located primarily in Dimmit, Frio and LaSalle counties. The NGL pipelines, which were completed in June 2015, include a Y-grade pipeline that connects our Woodsboro processing facility to Holdings' Robstown fractionator ("Robstown") and a propane pipeline from our Bonnie View fractionator to Robstown.
Because of the common control aspects in the 2015 Holdings Acquisition, the 2015 Holdings Acquisition was deemed a transaction between entities under common control and, as such, was accounted for on an “as if pooled” basis for all periods which common control existed (which began on August 4, 2014). The Partnership’s financial results retrospectively include the

91


financial results of the Valley Wells System and Compression Assets for all periods ending after August 4, 2014, the date of the Holdings Transaction, and before May 7, 2015. The consolidated net assets associated with the Valley Wells System and Compression Assets as of December 31, 2014 were $77.3 million and are presented in the consolidated balance sheets of the Partnership. The acquired NGL pipelines were accounted for as an asset acquisition and will be included in the historical financial statements beginning on May 7, 2015. As a carve-out transaction, the 2015 Holdings Acquisition has no cash accounts. As such, accounts receivable and accounts payable, along with certain other assets and liabilities that would be settled in cash, were the rights and obligations of Holdings as of December 31, 2014. Given their nature and the fact that carve-out financial statements are meant to represent an entity’s operations as if it had existed as of the time common control occurred, we have presented these amounts as third-party receivables and payables.
The amount of consideration paid below Holdings' net book value of the assets received and liabilities assumed of the 2015 Holdings Acquisition was recorded as an increase to partners' capital as summarized as follows (in thousands):
Consideration paid(1)
 
$
77,640

Total net assets contributed
 
107,356

Net assets contributed in excess of consideration paid
 
$
29,716

Allocation of increase to partners' capital:
 
 
Common limited partner interest
 
$
14,806

Class B Convertible limited partner interest
 
7,929

Subordinated limited partner interest
 
6,387

General Partner interest
 
594

Total increase to partners' capital
 
$
29,716

 
(1) This amount was calculated as follows: $15.0 million of cash plus 4.5 million new common units at an issue price of $13.92, the closing price of the Partnership’s common units on May 7, 2015.

Supplemental Disclosures - As If Pooled Basis. As noted above, the 2015 Holdings Acquisition was between commonly controlled entities which required that we account for the acquisitions in a manner similar to a pooling of interests. As a result, the historical financial statements of the Partnership and the Valley Wells System and Compression Assets have been combined to reflect the historical operations, financial position and cash flows from the date common control began on August 4, 2014. Revenues and net income for the previously separate entities and the combined amounts for the year ended December 31, 2015 and 2014, are as follows (in thousands):
 
Year Ended December 31,
 
2015
 
2014
Partnership revenues
$
691,424

 
$
842,728

Valley Wells System and Compression Assets revenue
7,049

 
5,785

Combined revenues
$
698,473

 
$
848,513

 
 
 
 
Partnership net loss
$
(51,235
)
 
$
(31,322
)
Valley Wells System and Compression Assets net loss
(4,258
)
 
(6,409
)
Combined net loss
$
(55,493
)
 
$
(37,731
)

4. TRANSACTION-RELATED COSTS
During the years ended December 31, 2015 and 2014, we recognized $2.5 million and $9.9 million, respectively, of transaction-related costs in connection with the Onyx acquisition, the Holdings Transaction, the TexStar Rich Gas System Transaction, the Texoz Acquisition and the Holdings Acquisition, which are recorded in operations and maintenance and general and administrative expenses. For the year ended December 31, 2015, these costs include $2.0 million related to the Holdings Acquisition and residual costs from the TexStar Rich Gas System Transaction. For the year ended December 31, 2014, these costs include (a) $7.2 million related to the accelerated vesting of the LTIP awards (as defined in Note 5) due to the change in control as further discussed in Note 13, (b) $1.7 million of advisory, audit and legal fees, (c) $0.6 million of charges associated with employees’ severance, (d) $0.3 million related to professional fees associated with the Onyx acquisition and the

92


Texoz Acquisition and (e) $0.1 million related to the accelerated vesting of the Southcross Energy LLC equity equivalent units due to the change in control as further discussed in Note 13.

5. EARNINGS PER LIMITED PARTNER UNIT AND DISTRIBUTIONS
Earnings Per Unit of the Partnership
The following is a reconciliation of net loss attributable to limited partners and the limited partner units used in the basic and diluted earnings per unit calculations for the years ended December 31, 2015, 2014 and 2013 (in thousands, except per unit data):
 
 
Year Ended December 31,
 
 
2015 (1)
 
2014 (1)
 
2013
Net loss
 
$
(55,493
)
 
$
(37,731
)
 
$
(15,970
)
Series A Preferred unit fair value adjustment(2)
 

 
(4,596
)
 
(37
)
Series A Preferred unit in-kind distribution
 

 
(534
)
 
(1,633
)
General partner unit in-kind distribution
 
(164
)
 
(207
)
 

Net loss attributable to Holdings
 
(4,258
)
 
(6,409
)
 

Net loss attributable to partners
 
$
(51,399
)
 
$
(36,659
)
 
$
(17,640
)
 
 
 
 
 
 
 
General partner's interest(3)
 
$
(1,084
)
 
$
(693
)
 
$
(319
)
Limited partners' Class B Convertible interest(3)
 
(14,225
)
 
(7,436
)
 

Limited partners' interest(2)
 
 
 
 
 
 
    Common
 
$
(24,790
)
 
$
(20,175
)
 
$
(8,683
)
    Subordinated
 
(11,300
)
 
(8,355
)
 
(8,638
)
____________________________________________________________________________
(1) We calculate historical earnings per unit with retrospective earnings or losses of a transferred business before the date of the 2015 Holdings Acquisition allocated entirely to the General Partner. The previously reported earnings per unit of the limited partners did not change as a result of the 2015 Holdings Acquisition.
(2) The valuation adjustment to maximum redemption value of the Series A Preferred Unit (defined below) in-kind distribution increased the net loss attributable to partners for the years ended December 31, 2014 and 2013 in the calculation of earnings per unit (See Note 11).
(3) General Partner's and limited partners’ interests are calculated based on the allocation of net losses for the period, net of the allocation of Series A Preferred Unit in-kind distributions, Series A Preferred Unit fair value adjustments and General Partner unit in-kind distributions. The Class B Convertible Unit interest is calculated based on the allocation of only net losses for the period.
 
 
Year Ended December 31,
Common Units
 
2015
 
2014
 
2013
Interest in net loss
 
$
(24,790
)
 
$
(20,175
)
 
$
(8,683
)
Effect of dilutive units - numerator(1)
 

 

 

    Dilutive interest in net loss
 
$
(24,790
)
 
$
(20,175
)
 
$
(8,683
)
 
 
 
 
 
 
 
Weighted-average units - basic
 
26,780,825

 
21,641,635

 
12,224,997

Effect of dilutive units - denominator(1)
 

 

 

    Weighted-average units - dilutive
 
26,780,825

 
21,641,635

 
12,224,997

 
 
 
 
 
 
 
Basic and diluted net loss per common unit
 
$
(0.93
)
 
$
(0.93
)
 
$
(0.71
)

93


 
 
Year Ended December 31,
Subordinated Units
 
2015
 
2014
 
2013
Interest in net loss
 
$
(11,300
)
 
$
(8,355
)
 
$
(8,638
)
Effect of dilutive units - numerator(1)
 

 

 

    Dilutive interest in net loss
 
$
(11,300
)
 
$
(8,355
)
 
$
(8,638
)
 
 
 
 
 
 
 
Weighted-average units - basic
 
12,213,713

 
12,213,713

 
12,213,713

Effect of dilutive units - denominator(1)
 

 

 

    Weighted-average units - dilutive
 
12,213,713

 
12,213,713

 
12,213,713

 
 
 
 
 
 
 
Basic and diluted net loss per subordinated unit
 
$
(0.93
)
 
$
(0.68
)
 
$
(0.71
)
____________________________________________________________________________
(1)Because we had a net loss for all periods for common units and the subordinated units, the effect of the dilutive units would be anti-dilutive to the per unit calculation. Therefore, the weighted average units outstanding are the same for basic and dilutive net loss per unit for those periods. The weighted average units that were not included in the computation of diluted per unit amounts were 17,168, 184,417 and 10,092 unvested awards granted under our LTIP for the years ended December 31, 2015, 2014 and 2013, respectively, and 1,213,257 Series A Preferred Units for the year ended December 31, 2013.

Our calculation of the number of weighted-average units outstanding includes the common units that have been awarded to our directors that are deferred under our Non-Employee Director Deferred Compensation Plan.

All of our Series A Convertible Preferred Units (“Series A Preferred Units”) were converted into common units on August 4, 2014 (See Note 11). Prior to conversion, our Series A Preferred Units were considered participating securities for purposes of the basic earnings per unit calculation during periods in which they received cash distributions. We were required to pay in-kind distributions to the Series A Preferred Units for the first four full quarters beginning the second quarter of 2013, and continued to pay these distributions until the Series A Preferred Units were converted into common units. Because the Series A Preferred Units received in-kind distributions, they have been excluded from the basic earnings per unit calculation for the year ended December 31, 2014.
Distributions
Our agreement of limited partnership, which was amended and restated on August 4, 2014 in order to establish the Class B Convertible Units (as amended and restated, the “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, as determined by our General Partner. There is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Beginning with the third quarter of 2014, until such time that we have a distributable cash flow divided by cash distributions ratio (“Distributable Cash Flow Ratio”) of at least 1.0, Holdings, the indirect holder of all of our subordinated units, waived the right to receive distributions on any subordinated units that would cause the Distributable Cash Flow Ratio to be less than 1.0. In addition, the Credit Agreement Amendment (as defined in Note 8) imposed additional restrictions on our ability to declare and pay quarterly cash distributions with respect to our subordinated units. See Note 8.
With respect to the fourth quarter of 2014, Holdings also waived the requirement that any distribution owed to it for that quarter be paid within 45 days of the end of the quarter, provided that the distribution was paid before or in conjunction with the filing of our 2014 Annual Report on Form 10-K. We paid a distribution of $0.28 per unit on our 12,213,713 subordinated units in conjunction with the filing of our 2014 Annual Report on Form 10-K.
Holdings did not receive a distribution for the first quarter of 2015 in respect of the 4.5 million common units acquired by it in connection with the 2015 Holdings Acquisition.
In January 2016 and effective for the fourth quarter of 2015, the board of directors of our General Partner voted not to pay a quarterly distribution and instead to reserve any excess cash for the operation of our business. Quarterly distributions were paid by the Partnership through the third quarter of 2015. The board of directors of our General Partner and our management believe this suspension to be in the best interest of our unitholders. The board of directors and management will continue to evaluate the Partnership's ability to reinstate the distribution in future periods.

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Although we have suspended distributions to holders of our Class B Convertible Units, such paid in-kind (“PIK”) distributions continue to accrue. Under the terms of our Partnership Agreement, we are required to pay or set aside for payment all accrued but unpaid PIK distributions with respect to the Class B Convertible Units prior to or contemporaneously with resuming any distribution with respect to our units.
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.
Cash Distributions
The following table represents our distributions paid for previous periods (in thousands, except per unit data): 

 
 
 
 
 
 
 
Distributions
 
 
Attributable to the
 
Per Unit
 
 
Limited Partners
 
 
 
 
Payment Date
 
Quarter Ended
 
Distribution
 
 
Common
 
Subordinated
 
General Partner
 
Total
2015
 
 
 
 
 
 
 
 
 
 
 
 
 
November 13, 2015
 
September 30, 2015
 
$
0.40

 
 
$
11,368

 
$

 
$
459

 
$
11,827

August 14, 2015
 
June 30, 2015
 
0.40

 
 
11,325

 

 
457

 
11,782

May 14, 2015
 
March 31, 2015
 
0.40

 
 
9,520

 

 
418

 
9,938

2014
 
 
 
 
 
 
 
 
 
 
 
 
 
February 13, 2015
 
December 31, 2014
 
0.40

 
(1) 
9,520

 
3,432

(3) 
416

 
13,368

November 14, 2014
 
September 30, 2014
 
0.40

 
(1) 
9,520

 

 
413

 
9,933

August 14, 2014
 
June 30, 2014
 
0.40

 
 
9,399

 
4,886

 
290

 
14,575

May 15, 2014
 
March 31, 2014
 
0.40

 
 
8,586

 
4,886

 
290

 
13,762

2013
 
 
 
 
 
 
 
 
 
 
 
 
 
February 14, 2014
 
December 31, 2013
 
0.40

 
 
8,581

 
4,885

 
289

 
13,755

November 14, 2013
 
September 30, 2013
 
0.40

 
 
4,888

 
4,885

 
214

 
9,987

August 14, 2013
 
June 30, 2013
 
0.40

 
 
4,890

 
4,886

 
210

 
9,986

May 15, 2013
 
March 31, 2013
 
0.40

 
 
4,888

 
4,886

 
199

 
9,973

2012
 
 
 
 
 
 
 
 
 
 
 
 
 
February 14, 2013
 
December 31, 2012
 
0.24

 
(2) 
2,931

 
2,931

 
120

 
5,982

____________________________________________________________________________
(1) The common unit distribution in the table above includes the distribution payment to the Series A Preferred unitholders for their Series A Preferred Units converted into common units or to the units that vested as part of our LTIP (as defined below) as a result of the Holdings Transaction (See Notes 1, 11 and 13).
(2) Per unit distribution of $0.24 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.
(3) Holdings waived the requirement that any distribution owed to it for the fourth quarter be paid within 45 days of the end of the quarter. We paid a distribution of $0.28 on our 12,213,713 subordinated units in conjunction with the filing of our 2014 Annual Report on Form 10-K.
 
In accordance with our LTIP, we paid the distribution equivalent rights to holders of LTIP units that vested during year ended December 31, 2014 (See Note 13). On November 14, 2013, we paid an aggregate distribution of $0.1 million to the holders of the vested phantom units.

Paid In-Kind Distributions

During the second quarter of 2013, we raised $40.0 million of equity through issuances of 1,715,000 Series A Preferred

95


Units and an additional General Partner contribution to satisfy the requirements of our Previous Credit Facility (as defined in Note 8) (See Notes 8 and 11). Under the terms of our Partnership Agreement, we were required to pay the holders of our Series A Preferred Units quarterly distributions of in-kind Series A Preferred Units for the first four full quarters following the issuance of the units and continuing thereafter until the board of directors of our General Partner determined to begin paying quarterly distributions in cash. In-kind distributions were in the form of Series A Preferred Units at a rate of $0.40 per outstanding Series A Preferred Unit per quarter (or 7% per year of the per unit purchase price). Cash distributions were required to equal the greater of $0.40 per unit per quarter or the quarterly distribution paid with respect to each common unit. In accordance with the Partnership Agreement, our General Partner received a corresponding distribution of in-kind general partner units to maintain its 2.0% interest in us. In connection with the Holdings Transaction (see Notes 1 and 3), all holders of the Series A Preferred Units elected to convert their Series A Preferred Units into 2,015,638 common units based on a 110% exchange ratio.

The following table represents the PIK distribution from the date of our IPO through August 4, 2014, the date on which all outstanding Series A Preferred Units were converted to common units (in thousands, except per unit and in-kind distribution units): 
Payment Date
 
Attributable to the Quarter Ended(1)
 
Per Unit Distribution
 
 
 
In-Kind Series A
Preferred Unit
Distributions
to Series A
Preferred 
Holders
 
In-Kind 
Series A
Preferred
Distributions
Fair Value
(2)
 
In-Kind 
Unit
Distribution
to General 
Partner
 
In-Kind General Partner Distribution Value(2)
2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
May 15, 2014
 
March 31, 2014
 
$
0.40

 
 
 
31,513

 
$
534

 
643

 
$
11

2013
 
 
 
 

 
 
 
 
 
 
 
 
 
 
February 14, 2014
 
December 31, 2013
 
0.40

 
 
 
30,971

 
558

 
632

 
11

November 14, 2013
 
September 30, 2013
 
0.40

 
 
 
30,439

 
511

 
621

 
10

August 14, 2013
 
June 30, 2013
 
0.35

 
(3) 
 
22,276

 
512

 
454

 
10

August 14, 2013
 
June 30, 2013
 
0.20

 
(4) 
 
2,199

 
51

 
45

 
1

____________________________________________________________________________
(1) As a result of the conversion, the Series A Preferred Unit holders (and the corresponding General Partner units) did not receive a PIK distribution for the quarters ended June 30, 2014 or September 30, 2014, but received a cash distribution on the converted common units.
(2) The fair value was calculated as required, based on the common unit price at the quarter end date for the period attributable to the distribution, multiplied by the number of units distributed.
(3) Per unit distribution of $0.35 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 issuance of 1,466,325 Series A Preferred Units and 29,925 general partner units on April 12, 2013.
(4) Per unit distribution of $0.20 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 issuance of 248,675 Series A Preferred Units and 5,075 general partner units on May 15, 2013.

Class B Convertible Units. In connection with the Contribution, on August 4, 2014, we established our Class B Convertible Units. The Class B Convertible Units consist of 14,633,000 of such units plus any additional Class B Convertible Units issued in-kind as a distribution (“Class B PIK Units”). The Class B Convertible Units are not participating securities for purposes of the earnings per unit calculation. Commencing with the quarter ended September 30, 2014 and until converted, as long as certain requirements are met, the holders of the Class B Convertible Units will receive quarterly distributions in an amount equal to $0.3257 per unit. These distributions will be paid quarterly in Class B PIK Units within 45 days after the end of each quarter. Our General Partner was entitled, and has exercised its right, to retain its 2.0% general partner interest in us in connection with the original issuance of Class B Convertible Units. In connection with future distributions of Class B PIK Units, the General Partner is entitled to a corresponding distribution to maintain its 2.0% general partner interest in us. The Class B Convertible Units have the same rights, preferences and privileges, and are subject to the same duties and obligations, as our common units, with certain exceptions. See Note 12.


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The following table represents the PIK distribution paid on the Class B Convertible Units for periods after August 4, 2014 and ended December 31, 2015 (in thousands, except per unit and in-kind distribution units):
Payment Date
Attributable to the Quarter Ended
Per Unit Distribution
 
In-Kind Class B Convertible Unit
Distributions to Class B Convertible Holders
 
In-Kind 
Class B Convertible Distributions
Value
(1)
 
In-Kind 
Unit
Distribution
to General 
Partner
 
In-Kind General Partner Distribution Value(1)
2015
 
 
 
 
 
 
 
 
 
 
November 13, 2015
September 30, 2015
$
0.3257

 
274,478

 
$
1,353

 
5,601

 
$
28

August 14, 2015
June 30, 2015
0.3257

 
269,758

 
2,994

 
5,505

 
61

May 14, 2015
March 31, 2015
0.3257

 
265,118

 
3,712

 
5,410

 
76

2014
 
 
 
 
 
 
 
 
 
 
February 13, 2015
December 31, 2014
0.3257

 
260,558

 
4,143

 
5,318

 
85

November 14, 2014
September 30, 2014
0.3257

 
256,078

 
5,467

 
5,226

 
112

____________________________________________________________________________
(1) The fair value was calculated as required, based on the common unit price at the quarter end date for the period attributable to the distribution, multiplied by the number of units distributed.

6. FINANCIAL INSTRUMENTS
Fair Value Measurements
We apply recurring fair value measurements to our financial assets and liabilities. In estimating fair value, we generally use a market approach and incorporate assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and/or the risks inherent in the inputs to the valuation techniques. The fair value measurement inputs we use vary from readily observable inputs that represent market data obtained from independent sources to unobservable inputs that reflect our own market assumptions that cannot be validated through external pricing sources. Based on the observability of the inputs used in the valuation techniques, the financial assets and liabilities carried at fair value in the financial statements are classified as follows:
Level 1—Represents unadjusted quoted market prices in active markets for identical assets or liabilities that are accessible at the measurement date. This category primarily includes our cash and cash equivalents, accounts receivable and accounts payable.
Level 2—Represents quoted market prices for similar assets or liabilities in active markets, quoted market prices in markets that are not active or other inputs that are observable or can be corroborated by observable market data. This category primarily includes variable rate debt, over-the-counter swap contracts based upon natural gas price indices and interest rate derivative transactions.
Level 3—Represents derivative instruments whose fair value is estimated based on internally developed models and methodologies utilizing significant inputs that are generally less readily observable from market sources. We do not have financial assets and liabilities classified as Level 3.

In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the level in the fair value hierarchy must be determined based on the lowest level input that is significant to the fair value measurement. An assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and consideration of factors specific to the asset or liability.
    
The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable represent fair values based on the short-term nature of these instruments. As of December 31, 2015 and 2014, the fair value of the debt funded through our credit facilities approximates its carrying amount primarily due to the variable nature of the interest rate of the instrument and is considered a Level 2 fair value measurement.
Derivative Financial Instruments
Interest Rate Derivative Transactions
We manage a portion of our interest rate risk through interest rate swaps and interest rate caps. In March 2012, we terminated an interest rate cap contract and entered into an interest rate swap contract with Wells Fargo Bank, N.A. The interest

97


rate swap had a notional value of $150.0 million, and a maturity date of June 30, 2014. We received a floating rate based upon one-month London Interbank Offered Rate (“LIBOR”) and paid a fixed rate under the interest rate swap of 0.54%.

The interest rate swap was designated as a cash flow hedge for accounting purposes at inception of the contract and, thus, to the extent the cash flow hedge was effective, unrealized gains and losses were recorded to accumulated other comprehensive income/loss and recognized in interest expense as the underlying hedged transactions (interest payments) were recorded. Any hedge ineffectiveness was recognized in interest expense immediately. We did not have any hedge ineffectiveness during the years ended December 31, 2014 and 2013.

In February 2014, we discontinued cash flow hedge accounting on a prospective basis as a result of the $148.5 million repayment of borrowings under our Previous Credit Facility (as defined in Note 8). The fair value of the interest rate swap recorded in accumulated other comprehensive loss at the cash flow hedge de-designation date was $0.1 million. This balance was reclassified into interest expense as interest on the hedged debt was recorded. No ineffectiveness was recorded as a result of the cash flow hedge de-designation. Changes in the fair value of the interest rate swap for the remainder of the contract term were recognized in interest expense.

We enter into interest rate swap contracts whereby we receive a floating rate and pay a fixed rate to reduce the risk associated with the variability of interest rates for our term loan borrowings. Our interest rate swap position was as follows (in thousands):
 
 
 
 
 
 
 
 
Estimated Fair Value
Notional Amount
 
Fixed Rate
 
Effective Date
 
Maturity Date
 
December 31, 2015
$
50,000

 
1.198
%
 
September 30, 2014
 
June 30, 2016
 
$
(34
)
50,000

 
1.196
%
 
September 30, 2014
 
June 30, 2016
 
(34
)
100,000

 
1.195
%
 
June 30, 2015
 
January 1, 2017
 
(101
)
 
 
 
 
 
 
 
 
$
(169
)

We enter into interest rate cap contracts to effectively limit our LIBOR-based interest rate risk on the portion of debt hedged at the contracted cap rate. Our interest rate cap position was as follows (in thousands):
 
 
 
 
 
 
 
 
Estimated Fair Value
Notional Amount
 
Cap Rate
 
Effective Date
 
Maturity Date
 
December 31, 2015
$
20,000

 
1.500
%
 
December 31, 2014
 
December 31, 2016
 
$
2

80,000

 
3.000
%
 
June 30, 2015
 
June 30, 2017
 
2

50,000

 
3.000
%
 
December 31, 2015
 
December 31, 2017
 
6

 
 
 
 
 
 
 
 
$
10


These interest rate derivatives are not designated as cash flow hedges and as a result, changes in fair value are recognized in interest expense immediately.

The fair value of our interest rate derivative transactions is determined based on a discounted cash flow method using contractual terms of the transactions. The floating coupon rate is based on observable rates consistent with the frequency of the interest cash flows. We have elected to present our interest rate derivatives net on the balance sheets. There was no effect of offsetting on the balance sheets as of December 31, 2015 and 2014.

The fair values of our interest rate derivative transactions were as follows (in thousands):
 
Significant Other Observable Inputs (Level 2)
 
Fair Value Measurement as of
 
December 31, 2015
 
December 31, 2014
Current interest rate derivative assets
$
6

 
$
27

Non-current interest rate derivative assets
4

 
27

Current interest rate derivative (liabilities)
(169
)
 
(175
)
Non-current interest rate derivative (liabilities)

 
(39
)
Total interest rate derivatives
$
(159
)
 
$
(160
)

98


The effect of the interest rate swap designated as a cash flow hedge in our statements of changes in partners’ capital and members’ equity and comprehensive loss was as follows (in thousands):
 
Year Ended December 31,
 
2015
 
2014
 
2013
Change in value recognized in other comprehensive loss - effective portion
$

 
$
(11
)
 
$
(148
)
Loss reclassified from accumulated other comprehensive loss to interest expense

 
221

 
415

There were no amounts of gains or losses reclassified into earnings as a result of the discontinuance of cash flow hedge accounting due to the lack of probability of the forecasted transaction occurring.
 
The realized and unrealized amounts recognized in interest expense associated with derivatives that are not designated as hedging instruments were as follows (in thousands):
 
Year Ended December 31,
 
2015
 
2014
 
2013
Unrealized loss (gain) on interest rate derivatives
$
(1
)
 
$
160

 
$

Realized loss on interest rate derivatives
416

 
316

 
108

Commodity Swaps
In our normal course of business, we periodically enter into month-ahead swap contracts to hedge our exposure to certain intra-month natural gas index pricing risk. We had no month-ahead swap contracts as of December 31, 2015. The total volume of outstanding month-ahead swap contracts as of December 31, 2014 was 12,000 MMBtu per day. We define these contracts as Level 2 because the index price associated with such contracts is observable and tied to a similarly quoted first-of-the-month natural gas index price.
We have elected to present our commodity swaps net on the balance sheets, however there are no offsetting liabilities for the periods presented. We had no outstanding commodity swaps at December 31, 2015. As of December 31, 2014, we had $0.1 million of recognized assets with no recognized liabilities. We did not have any cash collateral received or paid on our commodity swaps as of December 31, 2015 and 2014.
The realized and unrealized gain/loss on these derivatives, recognized in revenues in our statements of operations, were as follows (in thousands):
 
Year ended December 31,
 
2015
 
2014
 
2013
Realized gain (loss) on commodity swap derivatives
$
214

 
$
347

 
$
(659
)
Unrealized gain (loss) on commodity swap derivatives
(111
)
 
(8
)
 
120



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7. LONG-LIVED ASSETS
Property, Plant and Equipment
Property, plant and equipment consist of the following (in thousands):
 
Estimated
Useful Life
 
As of December 31,
 
 
2015
 
2014
Pipelines
15-30
 
$
542,790

 
$
488,592

Gas processing, treating and other plants
15
 
547,253

 
515,080

Compressors
7-15
 
72,750

 
62,741

Rights of way and easements
15
 
46,692

 
37,238

Furniture, fixtures and equipment
5
 
9,252

 
3,671

Capital lease vehicles
3-5
 
2,442

 
2,076

    Total property, plant and equipment
 
 
1,221,179

 
1,109,398

Accumulated depreciation and amortization
 
 
(212,991
)
 
(142,234
)
    Total
 
 
1,008,188

 
967,164

 
 
 
 
 
 
Construction in progress
 
 
32,214

 
63,858

Land and other
 
 
25,599

 
27,548

    Property, plant and equipment, net
 
 
$
1,066,001

 
$
1,058,570

Depreciation is provided using the straight-line method based on the estimated useful life of each asset. Depreciation expense for the years ended December 31, 2015, 2014 and 2013 was $70.8 million, $46.1 million and $33.5 million, respectively.
In January 2013, we shut down our Gregory facility to perform extensive turnaround maintenance activities and to connect additional equipment to enhance NGL recoveries. As the turnaround maintenance was nearing completion, we experienced a fire at this facility. In connection with the fire, as of December 31, 2014, we spent $5.5 million to return the facility to service and filed an insurance claim related to these costs. We recovered $1.0 million in 2013 and $3.9 million in 2014 from insurance proceeds for this loss, less a $0.3 million deductible, under our insurance policies. We received the remaining approximately $0.6 million outstanding at December 31, 2014 in January 2015.

In January 2015, we shut down our Gregory facility for four weeks due to a fire at the facility. We reached our insurance deductible as part of efforts to return the facility to service from the fire and recorded a receivable of $0.5 million in our consolidated balance sheets as of December 31, 2015 for amounts incurred above the deductible.
Intangible Assets
Intangible assets of $1.5 million as of December 31, 2015 and 2014, respectively, represent the unamortized value assigned to long-term supply and gathering contracts acquired in 2011. These intangible assets are amortized on a straight-line basis over the 30-year expected useful lives of the contracts through 2041. Amortization expense over the next five years related to intangible assets is not significant.

100


8. LONG-TERM DEBT
Our outstanding debt and related information at December 31, 2015 and 2014 is as follows (in thousands):
 
As of December 31,
 
2015
 
2014
Revolving credit facility due 2019
$
181,695

 
$
30,000

Term loans (including original issue discount of $1.8 million and $2.1 million as of December 31, 2015 and 2014, respectively) due 2021
441,464

 
445,629

Total long-term debt (including current portion)
623,159

 
475,629

Current portion of long-term debt
(4,500
)
 
(4,500
)
Debt issuance costs
(14,141
)
 
(16,602
)
Total long-term debt
$
604,518

 
$
454,527

Outstanding letters of credit
$
18,305

 
$
30,130

Remaining unused borrowings
$

 
$
139,870


 
Year Ended December 31,
 
2015
 
2014
Weighted average interest rate
5.16
%
 
4.61
%
Average outstanding borrowings
$
564,568

 
$
308,670

Maximum borrowings
$
624,945

 
$
491,875


 
 
Total
 
2016
 
2017
 
2018
 
2019
 
2020
 
Thereafter
Maturity
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt
$
624,945

 
$
4,500

 
$
4,500

 
$
4,500

 
$
186,195

 
$
4,500

 
$
420,750


Previous Credit Facility
In November 2012, we entered into a five-year $350.0 million revolving credit facility (as amended, the “Previous Credit Facility”). Borrowings under the Previous Credit Facility were set to mature in November 2017. We utilized the Previous Credit Facility for working capital requirements and capital expenditures, the purchase of assets, the payment of distributions and other general purposes. During 2013 and the first quarter of 2014, we entered into a total of four amendments to the Previous Credit Facility. In connection with these amendments, our availability was reduced from $350.0 million to the sum of $250.0 million, plus any amounts placed on deposit in a collateral account of our General Partner and letters of credit outstanding. This availability was increased to $350.0 million in connection with the fourth amendment in March 2014. In connection with the closing of the TexStar Rich Gas System Transaction, we refinanced our Previous Credit Facility and entered into the Senior Credit Facilities (as defined below).
Senior Credit Facilities

On August 4, 2014, in connection with the consummation of the Contribution and TexStar Rich Gas System Transaction, we entered into (a) the Third A&R Revolving Credit Agreement (as defined in Note 1) and (b) a Term Loan Credit Agreement with Wells Fargo Bank, N.A., as Administrative Agent, UBS Securities LLC and Barclays Bank PLC, as Co-Syndication Agents, and a syndicate of lenders (the “Term Loan Agreement” and, together with the Third A&R Revolving Credit Agreement, the “Senior Credit Facilities”). Subsequent to the balance sheet date and prior to the filing of our annual report, Wilmington Trust, National Association replaced Wells Fargo Bank, N.A. as Administrative Agent under the Term Loan Agreement, while Wells Fargo Bank, N.A. remained as the Administrative Agent under the Third A&R Revolving Credit Agreement. The initial borrowings and extensions of credit under the Term Loan Agreement were used to finance the TexStar Rich Gas System Transaction (including the immediate repayment of the $100 million of debt assumed in the transaction), the repayment of certain of our existing debt and the payment of fees and expenses in connection with the new debt arrangements and ongoing working capital and other general partnership purposes. No amounts were drawn initially on the Third A&R Revolving Credit Agreement. Substantially all of our assets are pledged as collateral under the Senior Credit Facilities, with the security interest of the facilities ranking pari passu.


101


Third A&R Revolving Credit Agreement

The Third A&R Revolving Credit Agreement is a five-year $200 million revolving credit facility (the “Credit Facility”). Borrowings under our Credit Facility bear interest at the LIBOR plus an applicable margin or a base rate as defined in the respective credit agreement. Pursuant to the Third A&R Revolving Credit Agreement, among other things:

(a)
the letters of credit sublimit increased to $75.0 million;

(b)
we have the right to increase the total commitments under the Credit Facility by obtaining additional commitments from other lenders, as long as our senior secured leverage ratio is less than or equal to 4.50 to 1.00 before and after giving effect to such increase, subject to certain other conditions;

(c)
the definition of “Change of Control” is amended to permit the combination transaction with TexStar and to reflect the Sponsors’ control of the General Partner;

(d)
our maximum consolidated total leverage ratio (i) was set at 5.75 to 1.00 as of the last day of the fiscal quarter ending December 31, 2014, (ii) 5.50 to 1.00 as of the last day of the fiscal quarter ending March 31, 2015, (iii) 5.25 to 1.00 as of the last day of the fiscal quarter ending June 30, 2015 and (iv) 5.00 to 1.00 as of the last day of each fiscal quarter thereafter;

(e)
we had the right, exercisable on or before the date that our annual audited financial statements were due for the 2014 fiscal year, to comply with the consolidated total leverage ratio, consolidated senior secured leverage ratio and the consolidated interest coverage ratio covenants (the “Financial Covenants”) by applying certain specified quarterly base periods and annualization methods pertaining to the TexStar Rich Gas System;

(f)
if we fail to comply with the Financial Covenants (a “Financial Covenant Default”), we have the right (which cannot be exercised more than two times in any twelve month period or more than four times during the term of the facility) to cure such Financial Covenant Default by having the Sponsors purchase equity interests in or make capital contributions to us resulting in, among other things, proceeds that, if added to consolidated EBITDA, as defined in the Third A&R Revolving Credit Agreement, would result in us satisfying the Financial Covenants;

(g)
certain definitions are amended to take into account the TexStar Rich Gas System; and

(h)
the negative covenants are amended to permit the entry into, and indebtedness under, the Term Loan Agreement.

Amendment to Third A&R Revolving Credit Agreement

During the fourth quarter of 2014 and into the first quarter of 2015, as a result of the decline in commodity prices and associated decline in upstream drilling activity, we experienced a decline in the growth in volume of natural gas we gather and process for our customers. This impacted our operating results adversely and resulted in the need to amend our Third A&R Revolving Credit Agreement.

On May 7, 2015, we entered into the First Amendment to our Third A&R Revolving Credit Agreement among the Partnership, as the borrower, Wells Fargo Bank, N.A., as the administrative agent, the lenders and other parties thereto (the “Credit Agreement Amendment”).

The Credit Agreement Amendment, among other things:

(a) (i) revised the maximum consolidated total leverage ratio set at 5.5 to 1.0 as of the last day of the fiscal quarter ending each of December 31, 2015, March 31, 2016 and June 30, 2016, (ii) 5.25 to 1.0 as of the last day of the fiscal quarter ending September 30, 2016, and (iii) 5.00 to 1.0 as of the last day of each fiscal quarter thereafter, in each case, without any step-ups in connection with acquisitions;

(b) increased the applicable margins used in connection with the loans and the commitment fee so that the applicable margin for Eurodollar Loans (as used in the Third A&R Revolving Credit Agreement) ranges from 2.00% to 4.50%, the applicable margin for base rate loans ranges from 1.00% to 3.50% and the applicable rate for commitment fees ranges from 0.375% to 0.500%;


102


(c) permits the Partnership to comply with certain Financial Covenants by making certain pro forma adjustments with respect to minimum revenues to be received from Frio;

(d) modified our ability to cure Financial Covenant defaults;

(e) imposed additional restrictions on our ability to declare and pay quarterly cash distributions with respect to our subordinated units;

(f) amended certain other provisions of the Third A&R Revolving Credit Agreement as more specifically set forth in the Credit Agreement Amendment; and

(g) allows us an unlimited number of quarterly equity cures related to our Financial Covenant Default through the fourth quarter of 2016, and no more than two in a twelve month period thereafter for the life of the agreement. Additionally, we are unable to borrow on our Credit Facility until we have funded the required equity cure for the applicable quarter; however, we retain the ability to fund the required equity cure using a contractual non-cash credit amount of up to $13.0 million, $10.0 million of which was used to fund equity cures in order to stay in compliance with the consolidated total leverage ratio for our Financial Covenants as of June 30, 2015 and September 30, 2015. The remaining $3.0 million will be used to fund a portion of the equity cure necessary to stay in compliance with the consolidated total leverage ratio for our Financial Covenants as of December 31, 2015.

Term Loan Agreement

The Term Loan Agreement is a seven-year $450 million senior secured term loan facility. On August 4, 2014, the lenders funded the full amount of the facility. Borrowings under our Term Loan Agreement bear interest at LIBOR plus 4.25% or a base rate as defined in the respective credit agreement with a LIBOR floor of 1.00%. Under the Term Loan Agreement, among other things:

(a)
subject to certain requirements, including the absence of a default and pro forma compliance under the Third A&R Revolving Credit Agreement and pro forma compliance with a senior secured leverage ratio less than or equal to 4.50 to 1.00 before and after giving effect to such increase, we may from time to time request incremental term loan commitments subject to certain other conditions;

(b)
we may seek commitments from third party lenders in connection with any incremental term loan commitment requests, subject to certain consent rights given to the administrative agent;

(c)
the guarantors and the collateral are the same as provided for the benefits of lenders in the Third A&R Revolving Credit Agreement;

(d)
subject to certain conditions, we may request that the lenders extend the seven-year maturity of all or a portion of the outstanding loans under the facility;

(e)
the facility is amortized in equal quarterly installments in an aggregate annual amount equal to 1% of the original principal amount of the initial loan ($1.125 million), with the remainder due on the maturity date;

(f)
there are customary mandatory prepayment provisions and, subject to certain conditions, permissive prepayment provisions; provided, that if certain repricing transactions occur, we must pay a call premium equal to 1% of the principal amount of the loans subject to the repricing transactions; and

(g)
there are customary representations and warranties, affirmative covenants, negative covenants and provisions governing an event of default (including acceleration of payment in connection with material indebtedness, including the Third A&R Revolving Credit Agreement).

See Note 2 for further detail.


103


Deferred Financing Costs

Deferred financing costs are capitalized and amortized as interest expense under the effective interest method over the term of the related debt. In connection with our adoption of the April 2015 FASB pronouncement simplifying the presentation of debt issuance costs, we retrospectively included the unamortized balance of deferred financing costs in long-term debt on the consolidated balance sheets. Changes in deferred financing costs are as follows (in thousands):
 
Year Ended December 31,
 
2015
 
2014
Deferred financing costs, January 1
$
16,602

 
$
5,237

Capitalization of deferred financing costs
698

 
15,659

Amortization of deferred financing costs(1)
(3,159
)
 
(4,192
)
Deferred financing costs, December 31
$
14,141

 
$
16,602

___________________________________________________________________________
(1) This amount includes $2.3 million written off in connection with repayment of the Previous Credit Facility and contemporaneously entering into the Senior Credit Facilities in August 2014.

9. COMMITMENTS AND CONTINGENT LIABILITIES
Legal Matters
On March 5, 2013, one of our subsidiaries, Southcross Marketing Company Ltd., filed suit in a District Court of Dallas County against Formosa Hydrocarbons Company, Inc. (“Formosa”).  The lawsuit sought 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 subsidiary 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.  After a bench trial held in January 2015, on February 5, 2015, the judge ruled that Formosa breached certain of its obligations under the gas processing and sales contract and that our subsidiary breached an obligation under each of the gas processing and sales contract and the related residue gas agreement.  The amount of damages awarded to our subsidiary was in excess of the damages awarded to Formosa. Rather than wait for the judge to award attorneys’ fees for each party as to the claims on which it prevailed, the parties have reached an agreement as to the appropriate award of attorneys’ fees. The amount of attorneys’ fees to be paid to our subsidiary is in excess of the attorneys’ fees to be paid to Formosa. After the ruling, our subsidiary filed a motion for reconsideration regarding a claim that was dismissed before trial through summary judgment. Formosa filed its own motion for reconsideration regarding the amount of damages awarded to our subsidiary on one of its claims. A hearing on both motions for reconsideration was held on June 5, 2015. The judge has yet to issue a ruling on these motions. Even if Formosa is successful in its request to reduce the damages awarded to our subsidiary, the amount of damages awarded to our subsidiary would still be in excess of the damages awarded to Formosa. No judgment will be entered until the judge has made a ruling on these motions. Regardless of how the judge rules on these motions, the judgment is not expected to have a material impact on our results of operations, cash flows or financial condition.
 
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. For example, during periods when we are expanding our operations through the development of new pipelines or the construction of new plants, we may become involved in disputes with landowners that are in close proximity to our activities. While we are currently involved in several such proceedings and disputes, our management believes that none of such proceedings or disputes 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.
Regulatory Compliance
In the ordinary course of our business, we are subject to various laws and regulations. In the opinion of our management, compliance with current laws and regulations will not have a material effect on our results of operations, cash flows or financial condition.

104


Leases
Capital Leases
 
We have auto leases classified as capital leases. The termination dates of the lease agreements vary from 2015 to 2019. We recorded amortization expense related to the capital leases of $0.5 million and $0.6 million for the year ended December 31, 2015 and 2014, respectively. Capital leases entered into during the year ended December 31, 2015 and 2014 were $0.4 million and $0.7 million, respectively. The capital lease obligation amounts included on the balance sheets were as follows (in thousands):
 
December 31, 2015
 
December 31, 2014
Other current liabilities
$
362

 
$
455

Other non-current liabilities
522

 
578

Total
$
884

 
$
1,033

 
Operating Leases
We maintain operating leases in the ordinary course of our business activities. These leases include those for office and other operating facilities and equipment. The termination dates of the lease agreements vary from 2015 to 2025. Expenses associated with operating leases, recorded in operations and maintenance expenses and general and administrative expenses in our statements of operations, were $5.3 million, $1.5 million and $1.5 million for the years ended December 31, 2015, 2014 and 2013, respectively. A rental reimbursement included in our lease agreement associated with the office space we leased in June 2015 of $2.3 million was recorded as a deferred liability on our consolidated balance sheets as of December 31, 2015. This amount will be amortized against the lease payments over the length of the lease term.
Future Minimum Lease Payments
Future minimum annual rental commitments under our capital and operating leases at December 31, 2015 were as follows (in thousands):
Years Ending December 31,
Capital Leases
 
Operating Leases
2016
$
373

 
$
3,634

2017
301

 
3,477

2018
192

 
3,409

2019
43

 
2,912

2020

 
1,148

Thereafter

 
4,912

Total future payments
909

 
$
19,492

Less: Imputed interest
$
(52
)
 
 
Future lease payments
$
857

 
 
Purchase Commitments
At December 31, 2015, we had commitments of approximately $4.2 million related primarily to the purchase of pipelines and compressors for our various capital expansion projects. We have other planned capital projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.

105


10. TRANSACTIONS WITH RELATED PARTIES
Charlesbank, EIG & Tailwater (our Sponsors)

Effective August 4, 2014, in connection with the Contribution and as a result of the Holdings Transaction, the board of directors of our General Partner includes one director affiliated with Charlesbank, one director affiliated with EIG, one director affiliated with Tailwater and three outside directors. On July 15, 2015, a fourth outside director was elected to serve on the board of directors of our General Partner. The eighth member of the board of directors of our General Partner, and its chairman, is David W. Biegler. Mr. Biegler will serve as chairman until the earlier of August 4, 2016 and his death or resignation. Our non-employee directors are reimbursed for certain expenses incurred for their services to us. The director services fees and expenses are included in general and administrative expenses in our statements of operations. We incurred fees and expenses related to the services from our affiliated directors as follows (in thousands):
 
Year Ended December 31,
 
2015
 
2014
 
2013
Charlesbank
$
148

 
$
340

 
$
463

EIG
64

 
20

 

Tailwater
64

 
20

 

Total fees and expenses paid for director services to affiliated entities
$
276

 
$
380

 
$
463


Southcross Energy Partners GP, LLC (our General Partner)
Our General Partner does not receive a management fee or other compensation for its management of us. However, our General Partner and its affiliates are entitled to reimbursements for all expenses incurred on our behalf, including, among other items, compensation expense for all employees required to manage and operate our business. We incurred expenses related to these reimbursements as follows (in thousands):
 
Year Ended December 31,
 
2015
 
2014
 
2013
Reimbursements included in general and administrative expenses
$
15,790

 
$
10,944

 
$
9,364

Reimbursements included in operations and maintenance expenses
20,045

 
16,093

 
13,264

Total reimbursements to our General Partner and its affiliates
$
35,835

 
$
27,037

 
$
22,628


Compensation expense for services incurred by us on behalf of Southcross Energy LLC was billed to Southcross Energy LLC for the years ended December 31, 2015 and 2014. Compensation expense not incurred on our behalf of $0.6 million and $0.9 million, respectively, was billed to Southcross Energy LLC.

In December 2014, Southcross Energy LLC, on behalf of us, paid the settlement of the $1.2 million liability in connection with the accelerated vesting of the 15,000 outstanding equity equivalent units held by management due to the change in control provision triggered by the Holdings Transaction. See Note 13.

We also provide management, administrative, operational and workforce related services to affiliated entities including Holdings, which owns 100% of our General Partner, and an affiliate that is jointly owned by EIG and Tailwater, two of our Sponsors. The expenses associated with these services, which are shared with these entities, are recorded in general and administrative expense in our statement of operations and are allocated in a manner approved by the board of directors and conflicts committee. For the years ended December 31, 2015 and 2014, we allocated $3.4 million and $1.0 million, respectively, to Holdings. For the year ended December 31, 2014, we allocated $0.1 million to an affiliate of two of our Sponsors.

In 2014, we paid approximately $2.8 million to Black Creek Well Services, LP, an entity in which two of our Sponsors (EIG and Tailwater) have an indirect controlling interest, for servicing work it performed for us.

During the second quarter of 2013, we issued and sold 1,715,000 Series A Preferred Units to Southcross Energy LLC for a cash purchase price of $22.86 per Series A Preferred Unit, in a privately negotiated transaction (See Note 11). After the Series A Preferred Units issuance during the second quarter of 2013, Southcross Energy LLC sold 1,500,000 of the units to third parties. All of the Series A Preferred Units, including those held by Southcross Energy LLC, were converted into common units on August 4, 2014 in connection with the Holdings Transaction. See Notes 1 and 11.

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Other Transactions with Affiliates
    
In conjunction with the TexStar Rich Gas System Transaction, we entered into a gas gathering and processing agreement (the “G&P Agreement”) and an NGL sales agreement (the “NGL Agreement”) with an affiliate of Holdings. Under the terms of these commercial agreements, we transport, process and sell rich natural gas for the affiliate of Holdings in return for agreed-upon fixed fees, and we can sell natural gas liquids that we own to Holdings at agreed-upon fixed prices. The NGL Agreement also permits us to utilize Holdings’ fractionation services at market-based rates.

In conjunction with the 2015 Holdings Acquisition, we entered into a series of commercial agreements with affiliates of Holdings including a gas gathering and treating agreement, a compression services agreement, a repair and maintenance agreement and an NGL transportation agreement. Under the terms of these commercial agreements, we gather, treat, transport, compress and redeliver natural gas for the affiliates of Holdings in return for agreed-upon fixed fees. In addition, under the NGL transportation agreement, we transport a minimum volume of NGLs per day at a fixed rate per gallon. The operational expense associated with such agreements has been capped at $1.7 million per quarter. During the year ended December 31, 2015, we exceeded this cap by $2.7 million which was recorded as a receivable from Holdings on our consolidated balance sheets.

During the years ended December 31, 2015 and 2014, the Partnership recorded revenues from affiliates of $94.7 million and $13.3 million in accordance with the G&P Agreement, the NGL Agreement and the commercial agreements entered into in connection with the 2015 Holdings Acquisition.
 
We had accounts receivable due from affiliates of $49.7 million and $11.3 million as of December 31, 2015 and 2014, respectively, and accounts payable due to affiliates of $7.9 million and $12.9 million as of December 31, 2015 and 2014, respectively. The affiliate receivable and payable balances are related primarily to transactions associated with Holdings, noted above, and our joint venture investments (defined in Note 15). Subsequent to the balance sheet date, but prior to the issuance of our annual report, the receivable due from Holdings of $43.0 million was brought current, as discussed in Notes 1 and 2.

During the year ended December 31, 2015, Holdings purchased $2.3 million of office leasehold improvements from SXE.

11. 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 Series A Preferred Units to Southcross Energy LLC during the second quarter of 2013 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. The Private Placement of Series A Preferred Units resulted in proceeds to us of $39.2 million. We also received a $0.8 million capital contribution from our General Partner to maintain its 2.0% general partner interest in us. Our total capital infusion of $40.0 million, from all sales of Series A Preferred Units and General Partner capital contributions, was used to reduce borrowings under our Previous Credit Facility (See Note 8).

All of the Series A Preferred Units, including units held by Southcross Energy LLC, were converted to common units on August 4, 2014 in connection with the Holdings Transaction. See Note 1 and below.
 
Because the Series A Preferred Units were equity instruments and redeemable at the option of the holder, they were classified outside of permanent equity.  The change of control rights associated with the Series A Preferred Units required the units to be classified outside of permanent equity.  The Series A Preferred Units were periodically adjusted to maximum redemption value because maximum redemption value was different than the fair value of the unit at the issuance date.
 
Voting Rights: The Series A Preferred Units were a class of voting equity security that rank senior to all of our other classes or series of equity securities with respect to distribution rights and rights upon liquidation.  The Series A Preferred Units had voting rights identical to the voting rights of the common units and voted with the common units as a single class, such that each Series A Preferred Unit (including each Series A Preferred Unit issued as an in-kind distribution, discussed below) was entitled to one vote for each common unit into which such Series A Preferred Unit was convertible on each matter with respect to which each common unit was entitled to vote.
 
Distribution Rights: Holders of Series A Preferred Units were entitled to quarterly distributions of in-kind Series A Preferred Units for the first four full quarters following the issue date of those units and continuing thereafter until the board of

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directors of our General Partner determined to begin paying quarterly distributions in cash, and thereafter in cash. In-kind distributions were in the form of Series A Preferred Units at a rate of $0.40 per outstanding Series A Preferred Unit per quarter (or 7% per year of the per unit purchase price). Cash distributions equaled the greater of $0.40 per unit per quarter or the quarterly distribution paid with respect to each common unit.
 
Conversion Rights: The Series A Preferred Units were convertible into common units based on an exchange ratio of 110% of the Series A Preferred Units in certain circumstances before January 1, 2015. In connection with the Holdings Transaction and pursuant to the change in control provision in our partnership agreement applicable to our Series A Preferred Units, all holders of the Series A Preferred Units elected to convert their Series A Preferred Units into 2,015,638 common units based on the 110% exchange ratio.

Dissolution and Liquidation: The Series A Preferred Units were senior to our common units with respect to rights on dissolution and liquidation. Common units issued upon conversion of the Series A Preferred Units have equal ranking with the rest of our common units with respect to rights on dissolution and liquidation.

12. PARTNERS' CAPITAL
Ownership
Our units outstanding as of December 31, 2015 are as follows (in units):
 
 
 
 
Partners’ Capital
 
 
 
 
 
 
 
 
 
 
 
 
 
Owned By Parent
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Series A
 
Public
 
Holdings
 
Class B
 
 
 
General
 
 
Preferred
 
Common
 
Common
 
Convertible
 
Subordinated
 
Partner
Units outstanding as of December 31, 2013
 
1,769,915

 
10,390,272

 

 

 
12,213,713

 
534,638

Issuance of common units
 

 
9,200,000

 

 

 

 
187,755

Holdings Transaction
 

 

 
1,863,713

 

 

 

Series A Convertible preferred conversion to common units
 
(1,832,399
)
 
1,762,951

 
252,687

 

 

 

Issuance of Class B Convertible Units
 

 

 

 
14,633,000

 

 

Vesting of LTIP units, net
 

 
331,320

 

 

 

 


In-kind distributions and general partner issuances to maintain 2.0% ownership
 
62,484

 

 

 
256,078

 

 
316,459

Units outstanding as of December 31, 2014
 

 
21,684,543

 
2,116,400

 
14,889,078

 
12,213,713

 
1,038,852

Common unit issuance related to the Holdings Acquisition
 

 

 
4,500,000

 

 

 

Board of Director grants
 

 
17,185

 

 

 

 

Vesting of LTIP units, net
 

 
102,491

 

 

 

 

In-kind distributions and general partner issuances to maintain 2.0% ownership
 

 

 

 
1,069,912

 

 
116,113

Units outstanding as of December 31, 2015
 

 
21,804,219

 
6,616,400

 
15,958,990

 
12,213,713

 
1,154,965

On November 29, 2013, we filed a Registration Statement on Form S-3 with 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.

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Common units
Our common units represent limited partner interests in us. The holders of our common units are entitled to participate in our distributions and are entitled to exercise the rights and privileges available to limited partners under our Partnership Agreement.

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 proceeds from the public offering were $144.7 million before expenses of $0.4 million related to the offering. The net proceeds from the offering were used for our Onyx acquisition in March 2014, to fund the construction of our pipeline system extending into Webb County, Texas and for general partnership purposes.
In connection with the TexStar Rich Gas System Transaction and the Holdings Transaction on August 4, 2014, we issued Class B Convertible Units, accelerated the vesting of awards under our LTIP, and all of the holders of our Series A Preferred Units elected to convert their Series A Preferred Units into common units based on an exchange ratio of 110%.
On May 7, 2015, we completed the 2015 Holdings Acquisition for total consideration of $77.6 million, consisting of $15.0 million in cash and 4.5 million new common units, valued as of the date of closing and issued to Holdings.
Class B Convertible Units

In connection with the Contribution, on August 4, 2014, we established our Class B Convertible Units. The Class B Convertible Units consist of 14,633,000 of such units plus any additional Class B PIK Units. The Class B Convertible Units have the same rights, preferences and privileges, and are subject to the same duties and obligations, as our common units, with certain exceptions as noted below.

Our Partnership Agreement does not allow additional Class B Convertible Units (other than Class B PIK Units) to be issued without the prior approval of our General Partner and the holders of a majority of the outstanding Class B Convertible Units. As of December 31, 2015, all of our outstanding Class B Convertible Units were indirectly owned by Holdings.

Distribution Rights: Commencing with the third quarter of 2014 and until converted, as long as certain requirements are met, the holders of the Class B Convertible Units will receive quarterly distributions in an amount equal to $0.3257 per unit paid in Class B PIK Units (based on a unit issuance price of $18.61) within 45 days after the end of each quarter. Our General Partner was entitled, and has exercised its right, to retain its 2.0% general partner interest in us in connection with the original issuance of Class B Convertible Units. In connection with future distributions of Class B PIK Units, the General Partner is entitled to a corresponding distribution to maintain its 2.0% general partner interest in us.

With the suspension of distributions to holders of our Class B Convertible Units, such PIK distributions continue to accrue. Distributions on the Class B Convertible Units are cumulative and will be payable in arrears when and if quarterly distributions are approved to be resumed by the board of directors of our General Partner.

Conversion Rights: The Class B Convertible Units are convertible into common units on a one-for-one basis and, once converted, will participate in cash distributions pari passu with all other common units. The conversion of Class B Convertible Units will occur on the date we (a) make a quarterly distribution equal to or greater than $0.44 per common unit, (b) generate Class B Distributable Cash Flow (as defined in our Partnership Agreement) in an amount sufficient to pay the declared distribution on all units for the two quarters immediately preceding the date of conversion (the “measurement period”) and (c) forecast paying a distribution equal to or greater than $0.44 per unit from forecasted Class B Distributable Cash Flow on all outstanding common units for the two quarters immediately following the measurement period.

Voting Rights: The Class B Convertible Units generally have the same voting rights as common units, and have one vote for each common unit into which such units are convertible.

Changes in Partners’ Capital due to Holdings Transaction

As discussed in Note 1, on August 4, 2014, Southcross Energy LLC and TexStar combined. As a result of this transaction, Holdings, through a wholly-owned subsidiary, (a) acquired 100% of TexStar and its general partner from BBTS Borrower LP and (b) acquired 2,116,400 of our common units and 12,213,713 of our subordinated units from Southcross Energy LLC. Thus, as a result of that transaction, Holdings acquired an approximate 57.4% limited partner interest in us at that time, as well as 100% of our General Partner, which owns an approximate 2.0% interest in us and our incentive distribution rights. BBTS Borrower LP was controlled by EIG and Tailwater. In November 2014, BBTS Borrower LP distributed to each of EIG and

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Tailwater, in relatively equal proportions, its interest in Holdings. The Holdings Transaction resulted in the Sponsors each indirectly owning approximately one-third of Holdings.    
Subordinated units
Subordinated units represent limited partner interests in us and convert to common units at the end of the Subordination Period (as defined in our Partnership Agreement). The principal difference between our common units and our subordinated units is that in any quarter during the Subordination Period, holders of the subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units do not accrue arrearages. Beginning with the third quarter of 2014, until such time we have a Distributable Cash Flow Ratio of at least 1.0, Holdings, the indirect holder of the subordinated units, has waived the right to receive distributions on any subordinated units that would cause the Distributable Cash Flow Ratio to be less than 1.0. In addition, the Credit Agreement Amendment imposed additional restrictions on our ability to declare and pay quarterly cash distributions with respect to our subordinated units.

With respect to the fourth quarter of 2014, Holdings also waived the requirement that any distribution owed to it for that quarter be paid within 45 days of the end of the quarter, provided that the distribution was paid before or in conjunction with the filing of our 2014 Annual Report on Form 10-K. We paid a distribution of $0.28 per unit on our 12,213,713 subordinated units in conjunction with the filing of our 2014 Annual Report on Form 10-K.
General Partner Interests
As defined by the Partnership Agreement, general partner units are not considered to be units (common or subordinated), but are representative of our general partner's 2.0% ownership interest in us. Our General Partner has received general partner unit PIK distributions in connection with the Private Placement (see Note 11) and the Class B Convertible Units. In connection with other equity issuances, including issuances related to the TexStar Rich Gas System Transaction and the Holdings Transaction, our General Partner has made capital contributions in exchange for additional general partner units to maintain its 2.0% ownership interest in us.
Equity Distribution Agreement
On November 12, 2014, we established a $75 million “at-the-market” equity offering program pursuant to an equity distribution agreement (the “Distribution Agreement”) with Wells Fargo Securities, LLC, J.P. Morgan Securities LLC and RBC Capital Markets, LLC (each, a “Manager” and, collectively, the “Managers”). Under the Distribution Agreement, we may offer and sell up to $75 million in aggregate gross sales proceeds of our common units (the “Offered Units”) from time to time through the Managers, each as our sales agent. Sales of the Offered Units, if any, made under the Distribution Agreement will be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices prevailing at the time of sale in block transactions, or as otherwise agreed upon by us and any Manager. The Offered Units have been registered under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Registration No. 333-192105 declared effective December 10, 2013, including the prospectus contained therein, as supplemented by the prospectus supplement filed with the SEC on November 12, 2014. We intend to use the net proceeds from the sale of the Offered Units, if any, for general partnership purposes, including the repayment of debt, acquisitions and funding capital expenditures. As of December 31, 2015, we have not sold any of the Offered Units pursuant to the Distribution Agreement.
The Distribution Agreement contains customary representations, warranties and agreements by us, including our obligations to indemnify the Managers for certain liabilities under the Securities Act. The Managers and certain of their affiliates have engaged, and may in the future engage, in commercial and investment banking transactions with us in the ordinary course of their business for which they have received, and expect to receive, customary compensation and expense reimbursement. In particular, affiliates of each of the Managers are lenders under our Senior Credit Facilities, an affiliate of Wells Fargo Securities, LLC is a lender under our Term Loan Agreement, and affiliates of the other sales agents may from time to time hold positions under the Term Loan Agreement. If we use any net proceeds of this offering to repay borrowings under our Senior Credit Facilities, such affiliates of the Managers will receive proceeds of the offering.
13. INCENTIVE COMPENSATION
Unit Based Compensation
Long-Term Incentive Plan
On November 7, 2012, and in connection with our IPO, we established the LTIP, which provides incentive awards to eligible officers, employees and directors of our General Partner. Awards granted to employees under the LTIP vest over a three year period in equal annual installments or in the event of a change in control of our General Partner in either a common unit or

110


an amount of cash equal to the fair market value of a common unit at the time of vesting, as determined by management at its discretion. These awards also include distribution equivalent rights that grant the holder the right to receive an amount equal to the cash distributions on common units during the period the award remains outstanding.
On November 9, 2015, the holders of a majority of our limited partnership units approved an amendment to the LTIP which increased the number of common units that may be granted as awards by 4,500,000 units. The term of the LTIP was also extended to a period of 10 years following the amendment's adoption.
The following table summarizes information regarding awards of units granted under the LTIP:
 
Units
 
Weighted-Average
Fair Value at Grant Date
Unvested - December 31, 2013
182,673

 
$
22.55

  Granted units
787,321

 
19.82

  Forfeited units
(1,050
)
 
23.01

  Units recaptured for tax withholdings
(159,500
)
 
17.06

  Vested units
(338,694
)
 
17.45

Unvested - December 31, 2014
470,750

 
$
20.45

  Granted units
594,333

 
11.82

  Forfeited units
(204,530
)
 
18.79

  Units recaptured for tax withholdings
(47,592
)
 
8.41

  Vested units
(125,041
)
 
10.36

Unvested - December 31, 2015
687,920

 
$
15.56

For the years ended December 31, 2015 and 2014, we granted awards under the LTIP, with a grant date fair value of $7.0 million and $15.6 million, respectively, which we have classified as equity awards. As of December 31, 2015 and 2014, we had total unamortized compensation expense of $7.6 million and $9.1 million, respectively, related to unvested awards. Compensation expense associated with awards granted in the year ended December 31, 2015 of 84,423 units is expected to be recognized over a one-year vesting period, while compensation expense for the remaining awards is expected to be recognized over the three-year vesting period from each equity award's grant date. The Holdings Transaction on August 4, 2014 resulted in a change of control of our General Partner and accelerated the vesting of all the LTIP awards and distribution equivalent rights outstanding on that date. As of December 31, 2015 and 2014, we had 5,058,073 and 900,284 units, respectively, available for issuance under the LTIP.
A grant of 84,423 units was made to the officers of our General Partner on March 10, 2015 that has a one-year vesting period rather than a three-year vesting period. These executive awards were not compensation earned for performance in 2014.
Unit Based Compensation Expense

The following table summarizes information regarding recognized compensation expense, which is included in general and administrative and operations and maintenance expense on our statements of operations (in thousands): 
 
Year Ended December 31,
 
2015
 
2014
 
2013
Unit-based compensation
$
4,573

 
$
10,074

(1) 
$
2,186

____________________________________________________________________________
(1) This amount includes $7.2 million related to the accelerated vesting of the LTIP awards and $0.1 million related to the vesting of the Southcross Energy LLC equity equivalent units as a result of the change in control that took place on August 4, 2014.
Southcross Energy LLC Phantom Units
Southcross Energy LLC provided certain key non-officer employees with equity incentive units ("Phantom Units") in Southcross Energy LLC. The Phantom Units vest upon the occurrence of a change in control where more than 50% of the voting power of Southcross Energy LLC changes hands, or upon the occurrence of a liquidity event where, through the sale of some portion of its ownership, the majority owner of Southcross Energy LLC achieves or exceeds a targeted rate of return on its original investment. The changes in structure and ownership as a result of our IPO did not create a change of control event under the vesting terms of the Phantom Units. The number of Phantom Units earned and eligible for vesting increases over a period of years or through the achievement of certain rates of return by the majority owner of the Southcross Energy LLC or a combination thereof. As of December 31, 2015, 2014 and 2013, no fair value was attributable to the Phantom Units. No

111


compensation expense associated with these units was recorded during the year ended December 31, 2015, 2014 and 2013. As of December 31, 2013, the number of authorized and issued Phantom Units was 10,832.
Southcross Energy LLC Equity Equivalent Units
On April 1, 2012, Southcross Energy LLC granted 15,000 equity equivalent units ("EEUs") to a member of management. Each individual EEU is equivalent in economic value to one Class A Common Unit of Southcross Energy LLC on a fully diluted basis. The EEUs had time and performance vesting over a three-year term. In conjunction with the closing of the Holdings Transaction, the 15,000 outstanding EEUs subject to change of control provisions vested on August 4, 2014. The Partnership recognized $0.1 million in general and administrative expenses in the statements of operations for the year ended December 31, 2014 in connection with the accelerated vesting of the EEUs. Compensation expense for the EEUs recognized in general and administrative expenses on the statements of operations was $0.6 million for the year ended December 31, 2013.
Employee Savings Plan
We have employee savings plans under Sections 401(a) and 401(k) of the Internal Revenue Code, as amended, whereby employees of our General Partner may contribute a portion of their base compensation to the employee savings plan, subject to limits. We provide a matching contribution each payroll period equal to 100% of the employee's contribution up to the lesser of 6% of the employee's eligible compensation or $18,000 annually for the period. The following table summarizes information regarding contributions and the expense recognized for the matching contributions, which is included in general and administrative expense on our statements of operations (in thousands): 
 
Year Ended December 31,
 
2015
 
2014
 
2013
Matching contributions expensed for employee savings plan
$
709

 
$
927

 
$
628


14. REVENUES
We had revenues consisting of the following categories (in thousands):
 
Year Ended December 31,
 
2015
 
2014
 
2013
Sales of natural gas
$
399,828

 
$
530,947

 
$
405,206

Sales of NGLs and condensate
154,478

 
226,218

 
169,523

Transportation, gathering and processing fees
138,717

 
90,807

 
59,392

Other
5,450

 
541

 
601

Total revenues
$
698,473

 
$
848,513

 
$
634,722



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15. INVESTMENTS IN JOINT VENTURES

Assets acquired through the TexStar Rich Gas System Transaction include equity interests in three joint ventures. During 2012, a subsidiary of TexStar and a company subsequently acquired by Atlas Pipeline Partners, L.P. ("Atlas") formed T2 Eagle Ford Gathering Company LLC (“T2 Eagle Ford”), T2 LaSalle Gathering Company LLC (“T2 LaSalle”) and T2 EF Cogeneration Holdings LLC (“T2 Cogen”) to construct and operate pipelines and a cogeneration facility located in South Texas. During 2015, Atlas was acquired by Targa, which is now our joint venture partner. We indirectly own a 50% interest in T2 Eagle Ford, a 50% interest in T2 Cogen and a 25% interest in T2 LaSalle. We pay our proportionate share of the joint ventures' operating costs, excluding depreciation and amortization, through lease capacity payments. As a result, our share of the joint ventures' losses is related primarily to the joint ventures' depreciation and amortization. The joint ventures’ summarized statements of operations data for the year ended December 31, 2015 and for the period from August 4, 2014 through December 31, 2014 is as follows (in thousands):
 
Year Ended December 31,
 
2015
 
2014
Revenue
 
 
 
T2 Eagle Ford
$
6,850

 
$
3,537

T2 Cogen
2,437

 
2,517

T2 LaSalle
1,297

 
1,163

 
 
 
 
Net loss
 
 
 
T2 Eagle Ford
$
(18,202
)
 
$
(6,277
)
T2 Cogen
(5,837
)
 
(4,281
)
T2 LaSalle
(5,860
)
 
(1,876
)

The Partnership’s equity in losses of joint venture investments is comprised of the following (in thousands):
 
Year Ended December 31,
 
2015
 
2014
T2 Eagle Ford
$
(9,068
)
 
$
(3,656
)
T2 Cogen
(2,919
)
 
(2,141
)
T2 LaSalle
(1,465
)
 
(699
)
Equity in losses of joint venture investments
$
(13,452
)
 
$
(6,496
)
The Partnership’s investments in joint ventures is comprised of the following (in thousands):
 
December 31, 2015
 
December 31, 2014
T2 Eagle Ford
$
105,755

 
$
108,185

T2 Cogen
16,747

 
19,615

T2 LaSalle
18,024

 
19,298

Investments in joint ventures
$
140,526

 
$
147,098


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The joint ventures’ summarized balance sheet data is as follows (in thousands):
 
December 31, 2015
 
December 31, 2014
T2 Cogen
 
 
 
Current assets
$
1,986

 
$
8,923

Property, plant and equipment, net
32,333

 
38,851

Total assets
34,319

 
47,774

Total liabilities
824

 
8,547

Total equity
33,495

 
39,227

Total liabilities and equity
$
34,319

 
$
47,774

 
 
 
 
T2 Eagle Ford
 
 
 
Current assets
$
4,525

 
$
4,173

Property, plant and equipment, net
217,370

 
216,863

Total assets
221,895

 
221,036

Total liabilities
9,697

 
3,915

Total equity
212,198

 
217,121

Total liabilities and equity
$
221,895

 
$
221,036

 
 
 
 
T2 LaSalle
 
 
 
Current assets
$
1,228

 
$
904

Property, plant and equipment, net
71,491

 
77,189

Total assets
72,719

 
78,093

Total liabilities
622

 
904

Total equity
72,097

 
77,189

Total liabilities and equity
$
72,719

 
$
78,093

16. CONCENTRATION OF CREDIT RISK
Our primary markets are in South Texas, Alabama and Mississippi. We have a concentration of revenues and trade accounts receivable due from customers engaged in the production, trading, distribution and marketing of natural gas and NGL products. These concentrations of customers may affect overall credit risk in that these customers may be affected similarly by changes in economic, regulatory or other factors. We analyze our customers’ historical financial and operational information before extending credit.
Our top ten customers for the years ended December 31, 2015, 2014 and 2013 represent the following percentages of consolidated revenue: 
 
 
Year Ended December 31,
 
 
2015
 
2014
 
2013
Top ten customers
 
54.2
%
 
63.4
%
 
59.7
%

The percentage of total consolidated revenue for each customer that exceeded 10% of total revenues for the years ended December 31, 2015, 2014 and 2013 was as follows: 
 
 
Year Ended December 31,
 
 
2015
 
2014
 
2013
Trafigura AG
 
(a)
 
13.6
%
 
11.7
%
____________________________________________________________________________
(a) Information is not provided for periods for which the customer or producer was less than 10% of our consolidated revenue.

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During the years ended December 31, 2015, 2014 and 2013, we did not experience significant nonpayment for services. We recorded an allowance for uncollectible accounts receivable of $0.1 million at December 31, 2015. We recorded no allowance for uncollectible accounts receivable at December 31, 2014 or 2013.
However, beginning in the second half of 2014 and continuing through the issuance of these financial statements, natural gas, crude oil and NGL prices have experienced increased volatility. Due to this continued volatility, some of our customers may experience material financial and liquidity issues. No significant nonpayment from customers has occurred as of December 31, 2015, however, we are aware of certain customers that have begun to undergo financial restructurings in 2016. We continue to monitor the proceedings of these customers' situations and will record an allowance for uncollectible accounts receivable at which time it may become necessary.
17. SUBSEQUENT EVENTS
Holdings Chapter 11 Reorganization

On March 28, 2016, Holdings and certain of its subsidiaries (other than us, our General Partner and our subsidiaries) filed a pre-packaged plan of reorganization (the “POR”) under Chapter 11 of the U.S. Bankruptcy Code in the Southern District of Texas to restructure its debt obligations and strengthen its balance sheet. Our operations, customers, suppliers, partners and other constituents were excluded from such proceeding. On April 11, 2016, the bankruptcy court confirmed Holdings’ POR, and on April 13, 2016, Holdings and its subsidiaries emerged from its bankruptcy and consummated the following principal transactions:

issued 33.34% of the limited partner interests of Holdings to the lenders under Holdings’ credit facility in exchange for the elimination of certain funded debt obligations;

issued 33.33% of the limited partner interests of Holdings to EIG in exchange for approximately $85 million in cash;

issued 33.33% of the limited partner interests of Holdings to Tailwater in exchange for approximately $85 million in cash;

committed to provide us $50 million (as part of the Equity Cure Agreement), from the $170 million in new equity contributed to Holdings from the Sponsors, to ensure we have sufficient liquidity to comply with the applicable financial covenants set forth in our credit agreement; and

paid all of the receivable due to us.

In addition, pursuant to the terms of the POR, the Lenders have the right to appoint two members (one of which must be independent) to the board of directors of our general partner due to their equity interest in Holdings. The directors appointed by the Lenders will replace the directors previously appointed by Charlesbank Capital Partners, LLC. The court authorized Holdings to continue to pay all of its trade creditors, suppliers and contractors, including us, in the ordinary course of business and any amounts owed by Holdings to these parties will not be impacted by the bankruptcy proceeding. We believe Holdings’ reorganization and POR will enhance our liquidity position, strengthen our balance sheet and position it to continue to support our business and growth.


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18. SUPPLEMENTAL INFORMATION
Supplemental Cash Flow Information (in thousands)
 
Year Ended December 31,
 
2015
 
2014
 
2013
Supplemental Disclosures:
 
 
 
 
 
Cash paid for interest
$
32,293

 
$
16,206

 
$
13,043

Cash received for tax refunds
58

 
205

 
95

Supplemental schedule of non-cash investing and financing activities:
 
 
 
 
 
Accounts payable related to capital expenditures
5,773

 
29,645

 
4,946

Change in value recognized in other comprehensive income

 
11

 
148

Capital lease obligation
378

 
708

 
1,396

Accrued distribution equivalent rights on the LTIP units
689

 
167

 
279

Series A Convertible preferred unit in-kind distributions and fair value adjustments

 
5,129

 

Class B Convertible unit issuance, net

 
324,413

 

Class B Convertible unit in-kind distributions
8,059

 
9,610

 

Consideration paid in excess of purchase price for the TexStar Rich Gas System

 
98,625

 

Settlement of EEU liability by Southcross Energy LLC

 
1,151

 

Consolidation of Valley Wells' net assets

 
33,165

 

Non-cash capitalized interest for 2015 Holdings Acquisition

 
323

 

Operating expenses for Valley Wells' assets due from Holdings
1,647

 

 

Net assets contributed in Holdings drop-down acquisition in excess of consideration paid
29,716

 

 

Purchase of assets in Holdings drop-down acquisition
62,640

 

 

Net liabilities assumed by Holdings in Holdings drop-down acquisition
1,436

 

 

Receivable from Holdings for purchase of office leasehold improvements
2,320

 

 

Capitalization of Interest Cost
We capitalize interest on projects during their construction period. Once a project is placed in service, capitalized interest, as a component of the total cost of the construction, is depreciated over the estimated useful life of the asset constructed.
We incurred the following interest costs (in thousands):
 
Year Ended December 31,
 
2015
 
2014
 
2013
Total interest costs
$
34,517

 
$
18,649

 
$
14,047

Capitalized interest included in property, plant and equipment, net
(1,779
)
 
(3,087
)
 
(1,457
)
Interest expense
$
32,738

 
$
15,562

 
$
12,590


SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The following presents a summary of selected quarterly financial information (in thousands, except per unit data):

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Quarters ended
2015
March 31 (1)
 
June 30 (1)
 
September 30 (1)
 
December 31
Revenues
$
185,939

 
$
167,220

 
$
179,569

 
$
165,745

Gross operating margin
44,824

 
42,625

 
46,168

 
47,699

(Loss) income from operations
(2,786
)
 
(3,938
)
 
2,406

 
(5,218
)
Net loss
(13,905
)
 
(15,450
)
 
(9,658
)
 
(16,480
)
Basic and diluted net loss per common unit
(0.21
)
 
(0.26
)
 
(0.17
)
 
(0.29
)
Basic and diluted net loss per subordinated unit
(0.21
)
 
(0.26
)
 
(0.17
)
 
(0.29
)
 
Quarters ended
2014
March 31
 
June 30
 
September 30 (1)
 
December 31 (1)
Revenues
$
213,591

 
$
195,063

 
$
212,676

 
$
227,182

Gross operating margin
27,188

 
26,237

 
32,115

 
41,841

(Loss) income from operations
1,692

 
(1,134
)
 
(15,658
)
 
1,872

Net loss
(1,289
)
 
(2,961
)
 
(26,032
)
(2) 
(7,448
)
Basic and diluted net (loss) income per common unit
(0.06
)
 
(0.34
)
 
(0.49
)
 
(0.05
)
Basic and diluted net (loss) income per subordinated unit
(0.06
)
 
(0.11
)
 
(0.49
)
 
(0.05
)
____________________________________________________________________________
(1) The 2015 Holdings Acquisition was deemed a transaction between entities under common control and, as such, was accounted for on an “as if pooled” basis for all periods which common control existed (which began on August 4, 2014). The Partnership’s financial results retrospectively include the financial results of the Valley Wells System and the Compression Assets for all periods ending after August 4, 2014, the date of the Holdings Transaction.
(2) See Note 4.

Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None

Item 9A.
Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Under the direction of our general partner’s Chief Executive Officer and Chief Financial Officer, we evaluated our disclosure controls and procedures and concluded that our disclosure controls and procedures were effective as of December 31, 2015.

Management’s Report on Internal Control Over Financial Reporting

Our General Partner's management is responsible for establishing and maintaining adequate internal control over our financial reporting. With our participation, an evaluation of the effectiveness of our internal control over financial reporting was conducted as of December 31, 2015, based on the framework and criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Based on this evaluation, our General Partner’s management has concluded that our internal control over financial reporting was effective as of December 31, 2015.
This annual report does not include an attestation report of our independent registered public accounting firm on internal control over financial reporting due to an exemption established by the JOBS Act for “emerging growth companies.”

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Changes in Internal Control
No change in internal control over financial reporting occurred during the quarter ended December 31, 2015, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.
Other Information
On April 13, 2016, in connection with Holdings' emergence from bankruptcy and in accordance with the terms of Holdings' POR, Jon M. Biotti resigned from the board of directors of Southcross Energy Partners GP, LLC, the general partner of Southcross Energy Partners, L.P. (the “Partnership”). Mr. Biotti's resignation was not the result of any disagreements with the Partnership regarding any matter related to its operations, policies, practices or otherwise.
On April 12, 2016, the board of directors of our General Partner awarded our Named Executive Officers cash awards under the 2016 Cash-Based Long-Term Incentive Plan (the “2016 Cash LTIP”). The board of directors of our General Partner approved the 2016 Cash LTIP on March 11, 2016.
The 2016 Cash LTIP provides for the grant, from time to time, of cash awards to certain of our employees. The 2016 Cash LTIP is administered by the board of directors of our General Partner, although such administration function may be delegated to a committee (including the Compensation Committee) comprised solely of two or more nonemployee directors. The 2016 Cash LTIP is designed to promote our interests by strengthening our ability to retain and motivate our employees.
Awards under the 2016 Cash LTIP (each, a “2016 Cash LTIP Award”) are subject to the vesting of the cash award upon specified future dates. A third of each 2016 Cash LTIP Award will vest on each of April 1, 2017, April 1, 2018, and April 1, 2019, subject to continued employment through the applicable vesting date. Generally, upon the grantee’s cessation of employment, any cash awarded pursuant to a 2016 Cash LTIP Award that has not vested will be forfeited. However, if the employee is terminated without cause (as defined in the LTIP), then such employee is entitled to receive the portion of the 2016 Cash LTIP Award that would have been payable on the next vesting date, but shall forfeit any further unvested 2016 Cash LTIP Award. A 2016 Cash LTIP Award shall vest in full, subject to continued employment through the certain event, upon a termination due to death or disability (as defined in the LTIP) or a change of control (as defined in the 2016 Cash LTIP).
Under the 2016 Cash LTIP, Mr. Bonn was awarded $900,000, Mr. Moxley was awarded $480,000, and Mr. Allan was awarded $390,000.
The foregoing description of the 2016 Cash LTIP and 2016 Cash LTIP Awards is not complete and is qualified in its entirety by reference to the full text of the 2016 Cash LTIP and the form of 2016 Cash LTIP Award, which are attached as Exhibit 10.18 to this Form 10-K and incorporated herein by reference.


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Item 10.
Directors, Executive Officers and Corporate Governance
Management of Southcross Energy Partners, L.P.
Southcross Energy Partners, L.P. is managed by the directors and executive officers of our General Partner. Our General Partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. Holdings owns 100% of our General Partner. Our General Partner has a board of directors, and our unitholders are not entitled to elect the directors or to directly or indirectly participate in our management or operations. Our General Partner will be liable, as the General Partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our General Partner.
Director Independence
Although most companies listed on the NYSE are required to have a majority of independent directors serving on the board of directors of the listed company, the NYSE does not require a listed publicly traded master limited partnership like us to have a majority of independent directors on the board of directors of its general partner.
Committees of the Board of Directors
The board of directors of our General Partner has an Audit Committee, a Conflicts Committee and a Compensation Committee and may have any such other committee as the board of directors shall determine from time to time. Each of the standing committees of the board of directors of our General Partner has the composition and responsibilities described below.
Conflicts Committee
Jerry W. Pinkerton, Nicholas J. Caruso and Bruce A. Williamson serve as the members of our Conflicts Committee. Mr. Pinkerton serves as the chairman of the Conflicts Committee. Our Partnership Agreement provides that the Conflicts Committee, as delegated by the board of directors of our General Partner as circumstances warrant, will review conflicts of interest between us and our General Partner or between us and affiliates of our General Partner. If a matter is submitted to the Conflicts Committee for its review and approval, the Conflicts Committee will determine if the resolution of a conflict of interest that has been presented to it by the board of directors of our General Partner is fair and reasonable to us. The current members of the Conflicts Committee and any future members may not be officers or employees of our General Partner, directors, officers or employees of our General Partner's affiliates or a holder of any ownership interest in our General Partner, its affiliates or the Partnership, except for common units and certain awards given to directors in their capacity as a director. In addition, they must comply with the independence standards established by the NYSE and the Exchange Act for service on an audit committee of a board of directors. Any matters approved by the Conflicts Committee will be conclusively deemed to have been approved in good faith, to be fair and reasonable to us, approved by all of our partners and not a breach by our General Partner of any duties it may owe us or our unitholders.
Audit Committee
Jerry W. Pinkerton, Nicholas J. Caruso, Ronald G. Steinhart and Bruce A. Williamson serve as the members of the Audit Committee. Mr. Pinkerton serves as the chairman of the Audit Committee. The Audit Committee oversees, reviews, acts on and reports on various auditing and accounting matters to the board of directors of our General Partner, including: (i) the selection of our independent accountants, (ii) the scope of our annual audits, (iii) fees to be paid to the independent accountants, (iv) the performance of our independent accountants, (v) the review of our internal controls process and (vi) our accounting practices. In addition, the Audit Committee oversees our compliance programs relating to legal and regulatory requirements. Messrs. Pinkerton, Caruso, Steinhart and Williamson comply with the independence and experience standards established by the NYSE and the Exchange Act for service on an audit committee of a board of directors. Our General Partner is generally required to have at least three independent directors serving on its board of directors at all times. Messrs. Pinkerton, Caruso and Steinhart are each audit committee financial experts.
Compensation Committee
Ronald G. Steinhart, Bruce A. Williamson and Jason H. Downie serve as the members of the Compensation Committee. Mr. Downie serves as the chairman of the Compensation Committee. The Compensation Committee establishes salaries, incentive compensation and other forms of compensation for officers, non-employee directors and other employees, as well as administers our incentive compensation and benefit plans.


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Directors and Executive Officers
Directors are appointed for a term of one year and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the discretion of the board of directors. The following table shows information for the directors and executive officers of our General Partner.
Name
Age
 
Position with Southcross Energy Partners GP, LLC
John E. Bonn
59

 
President and Chief Executive Officer
Joel D. Moxley
58

 
Senior Vice President and Chief Commercial Officer
Bret M. Allan
47

 
Senior Vice President and Chief Financial Officer
Kelly J. Jameson
51

 
Senior Vice President, General Counsel and Corporate Secretary
G. Tracy Owens
53

 
Vice President and Chief Accounting Officer
David W. Biegler
69

 
Chairman of the Board and Director
 
 
 
 
Jason H. Downie
45

 
Director
Wallace Henderson
54

 
Director
Jerry W. Pinkerton
75

 
Director
Ronald G. Steinhart
75

 
Director
Bruce A. Williamson
56

 
Director
Nicholas J. Caruso
70

 
Director
John E. Bonn
John E. Bonn was elected President and Chief Executive Officer of our General Partner in December 2014. Mr. Bonn also served as President and Chief Operating Officer from March 2014 to December 2014. Since December 2014, Mr. Bonn has also served as the President and Chief Executive Officer of Southcross Holdings GP LLC, the general partner of Holdings ("Holdings GP"). On March 28, 2016, Holdings GP, Holdings and certain of Holdings' subsidiaries filed for bankruptcy. On April 11, 2016, the bankruptcy court confirmed Holdings' plan of reorganization, and on April 13, 2016, Holdings GP, Holdings and Holdings' subsidiaries emerged from bankruptcy.

Before joining our General Partner and Holdings GP in March 2014, Mr. Bonn, was president of NiSource Midstream Services LLC, a midstream services company and subsidiary of NiSource Inc., from April 2011 to June 2013, as well as President of Pennant Midstream, LLC, a midstream services company. While at NiSource, he was responsible for building its midstream business in the Appalachian Basin and successfully sourcing and overseeing midstream opportunities in the Marcellus and Utica shale plays, including natural gas gathering, processing and liquids handling. From January 2010 to March 2011, Mr. Bonn was the Owner and President of Ranger Interests, Inc. From 2006 to 2009, Mr. Bonn was Vice President of Enterprise Product Partners L.P., a midstream services company. Mr. Bonn has over 32 years of experience in the midstream energy sector and has held various management and senior leadership positions with various energy companies, including GulfTerra Energy Partners LP, El Paso Field Services and Delhi Gas Pipeline.

Mr. Bonn earned a bachelor’s degree in Agricultural Engineering from Texas A&M University and served as an officer in the United States Army before entering the energy industry. Mr. Bonn currently serves on the board of directors of the Texas Pipeline Association and the Texas Aggie Corps of Cadets Association. Mr. Bonn is a past president of the North Texas Electric Power and Natural Gas Society and served on the Executive Committee of the Marcellus Shale Coalition. Mr. Bonn is also a past board member of the New Mexico Oil & Gas Association and the National Energy Service Association.
Joel D. Moxley
Joel D. Moxley was appointed Senior Vice President and Chief Commercial Officer of our General Partner in June 2015. Since June 2015, Mr. Moxley has also served as the Senior Vice President and Chief Commercial Officer of Holdings GP. On March 28, 2016, Holdings GP, Holdings and certain of Holdings' subsidiaries filed for bankruptcy. On April 11, 2016, the bankruptcy court confirmed Holdings' plan of reorganization, and on April 13, 2016, Holdings GP, Holdings and Holdings' subsidiaries emerged from bankruptcy.
Before joining the General Partner and Holdings GP, Mr. Moxley served as Senior Vice President of Operations Services for Crestwood Equity Partners LP and Crestwood Midstream Partners LP (collectively, “Crestwood”), both midstream master limited partnerships. The two entities were formed in May 2013 and October 2013, respectively, through a merger between

120


Inergy, L.P. and Crestwood Holdings GP, which became collectively Crestwood Equity Partners LP, and a merger between Crestwood Midstream Partners LP and Inergy Midstream, L.P., which became collectively Crestwood Midstream Partners LP. Mr. Moxley’s responsibilities included oversight of a variety of functions including human resources, information technology, operational engineering, supply chain, risk management and safety and regulatory that supported Crestwood. From October 2010 to May 2013, Mr. Moxley was the Chief Operating Officer for Crestwood Holdings GP and Crestwood Midstream Partners LP, where Mr. Moxley was responsible for operations, commercial, engineering, environmental, safety, regulatory and supply chain activities. From April 2008 to October 2010, Mr. Moxley was a part of a team that evaluated midstream acquisition opportunities on behalf of a private equity sponsor that ultimately acquired Quicksilver Gas Services LP, a midstream master limited partnership, which was subsequently renamed Crestwood Midstream Partners LP. Prior to joining companies now affiliated with Crestwood, Mr. Moxley was Senior Vice President of Crosstex Energy, L.P. (“Crosstex”) with responsibility for the commercial activities of Crosstex’s South Louisiana gas processing and NGL fractionation assets as well as the marketing of NGLs for Crosstex companywide. Mr. Moxley’s experience also includes midstream leadership roles at Enterprise Products Partners L.P., El Paso Corporation, PG&E Corporation, Valero Energy Corporation and Occidental Petroleum.
Mr. Moxley received a bachelor’s degree in Chemical Engineering from Rice University. He is also the immediate past Chairman of the Gas Processors Association and has served as a board member of the Texas Pipeline Association and the Petrochemical Feedstock Association of the Americas.
Bret M. Allan
Bret M. Allan was appointed Senior Vice President and Chief Financial Officer of our General Partner in June 2015. Since June 2015, Mr. Allan has also served as the Senior Vice President and Chief Financial Officer of Holdings GP. On March 28, 2016, Holdings GP, Holdings and certain of Holdings' subsidiaries filed for bankruptcy. On April 11, 2016, the bankruptcy court confirmed Holdings' plan of reorganization, and on April 13, 2016, Holdings GP, Holdings and Holdings' subsidiaries emerged from bankruptcy.

Prior to joining our General Partner and Holdings GP, Mr. Allan was Vice President, Finance and Treasurer for Energy Transfer Partners, L.P. From 2010 through 2015, Mr. Allan led the treasury, cash management, credit and corporate planning functions for Regency Energy Partners LP, a midstream master limited partnership within the Energy Transfer group. While at Regency, Mr. Allan helped lead numerous capital raising transactions and supported numerous acquisitions and recapitalizations.

Before joining Regency, Mr. Allan held various managerial positions at Energy Future Holdings and its predecessor company, TXU Corp., including positions in strategic planning, financial analysis and risk. Mr. Allan received a bachelor’s degree in economics from the University of California at Berkeley and holds a master’s degree in business administration with a concentration in finance from the University of Chicago Graduate School of Business.
Kelly J. Jameson
Kelly J. Jameson was appointed Senior Vice President, General Counsel and Corporate Secretary of our General Partner in September 2015. Since September 2015, Mr. Jameson has also served as the Senior Vice President, General Counsel and Corporate Secretary of Holdings GP. On March 28, 2016, Holdings GP, Holdings and certain of Holdings' subsidiaries filed for bankruptcy. On April 11, 2016, the bankruptcy court confirmed Holdings' plan of reorganization, and on April 13, 2016, Holdings GP, Holdings and Holdings' subsidiaries emerged from bankruptcy.
Prior to joining our General Partner and Holdings GP, Mr. Jameson was Associate General Counsel at USA Compression Partners, LP having previously served as Senior Vice President, General Counsel and Corporate Secretary of Crestwood Midstream Partners from 2010 to 2013. Mr. Jameson was employed by TransCanada Corporation from 2007 to 2010, where he was Senior Counsel and Corporate Secretary for the U.S. subsidiaries of TransCanada Corporation. From 1996 to 2007, Mr. Jameson served as Senior Counsel and Assistant Corporate Secretary for El Paso Corporation, and from 1993 to 1996, he served as Vice President and General Counsel for Cornerstone Natural Gas Company, Inc. Mr. Jameson received a bachelor’s degree in business administration from Southern Methodist University and a juris doctor degree from Oklahoma City University. Mr. Jameson is a member of the Texas Bar Association.
G. Tracy Owens
G. Tracy Owens was appointed Vice President and Chief Accounting Officer of our General Partner in August 2015. Since August 2015, Mr. Owens has also served as the Vice President and Chief Accounting Officer of Holdings GP. On March 28, 2016, Holdings GP, Holdings and certain of Holdings' subsidiaries filed for bankruptcy. On April 11, 2016, the bankruptcy

121


court confirmed Holdings' plan of reorganization, and on April 13, 2016, Holdings GP, Holdings and Holdings' subsidiaries emerged from bankruptcy.
Prior to joining our General Partner and Holdings GP, Mr. Owens served as Controller for Alon USA Energy, Inc. (“Alon”), a company specializing in the refining and marketing of petroleum products, from 2006 to 2015. In his role at Alon, Mr. Owens oversaw the accounting department consisting of approximately 40 personnel, the filing of quarterly and yearly financial reports, internal controls over financial reporting, and coordinating with external and internal auditors. Prior to joining Alon, Mr. Owens served as Controller for Hunt Refining Company from 1996 to 2006 and as Senior Manager at KPMG LLP from 1986 to 1996. Mr. Owens received a bachelor’s degree in business administration from Baylor University.
Mr. Owens is a Certified Public Accountant licensed by the State of Texas and is a member of both the American Institute of Certified Public Accountants and the Texas Society of Certified Public Accountants.
David W. Biegler
David W. Biegler has served as Chairman of the board of directors of our General Partner since August 2011. Mr. Biegler served as Chairman of the board of directors and Chief Executive Officer of our General Partner from August 2011 to December 2014 and as President of our General Partner from October 2012 to March 2014. Since July 2009, Mr. Biegler served as chairman of the board of directors and chief executive officer of Southcross Energy LLC. Since August 2014, Mr. Biegler has also served as the Chairman of the board of directors of Holdings GP and Chief Executive Officer of Holdings GP through December 2014. On March 28, 2016, Holdings GP, Holdings and certain of Holdings' subsidiaries filed for bankruptcy. On April 11, 2016, the bankruptcy court confirmed Holdings' plan of reorganization, and on April 13, 2016, Holdings GP, Holdings and Holdings' subsidiaries emerged from bankruptcy.
Mr. Biegler has more than 49 years of experience in the energy industry, having held various management positions in upstream, midstream, downstream, electric generation and oilfield services companies. From 2004 until 2012, Mr. Biegler served as chairman and chief executive officer of Estrella Energy LP, an entity formed for the purpose of acquiring midstream companies, which was a founding investor in our predecessor.
From 2002 to 2004, Mr. Biegler was Chairman of the board of Regency Gas Services, a midstream company that he co-founded and that was ultimately sold to a private equity firm. He retired as Vice Chairman of the board of TXU Corp. (now Energy Future Holdings Corp.) in 2001, a position he assumed earlier that year. From 1997 to 2001, Mr. Biegler served as President and Chief Operating Officer of TXU Corp., the result of a merger between Texas Utilities and ENSERCH Corp. From 1966 to 1997, he held various management positions at ENSERCH Corp. and its upstream, midstream, downstream and oilfield field services subsidiaries, including as ENSERCH’s Chairman, President and Chief Executive Officer from 1994 to 1997. Mr. Biegler received a bachelor’s degree in physics from St. Mary’s University, San Antonio, and is a graduate of Harvard University’s advanced management program.
Mr. Biegler also serves on the board of Southwest Airlines Co., Trinity Industries, Inc. and Austin Industries. He is a past director of Dynegy, Inc., Guaranty Financial Group and Animal Health International, Inc. He previously served as a member of the National Petroleum Council and as Chairman of the American Gas Association, the Southern Gas Association, the American Gas Foundation and the Texas Pipeline Association.
Mr. Biegler was selected to serve as Chairman for a two-year term or until his earlier death or resignation by the majority of the directors of our General Partner, as a result of contractual arrangements entered into in connection with the Holdings Transaction.
Nicholas J. Caruso
Nicholas J. Caruso was elected as an independent member of the board of directors of our General Partner in July 2015. Mr. Caruso serves as a member of the Audit Committee and the Conflicts Committee of the board of directors of our General Partner. With respect to the Audit Committee, Mr. Caruso qualifies as an "audit committee financial expert." Mr. Caruso has more than 45 years of management, finance and accounting experience. He was Executive Vice President and Chief Financial Officer of Dynegy Holdings, Inc. from 2002 through 2005, where he was responsible for the company’s treasury, insurance and audit functions. Prior to Dynegy, Mr. Caruso spent more than 30 years with Shell Oil Company in positions of increasing responsibility until his retirement in 2001. He last served as Shell’s Vice President of Finance and Chief Financial Officer and worked directly with Shell’s board of directors to implement internal controls and review financial results. Prior to being named CFO, Mr. Caruso served as Shell’s Controller and General Auditor. Mr. Caruso received a bachelor’s degree in accounting from Louisiana State University.

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The members of our General Partner appointed Mr. Caruso to serve as a director due to his audit, accounting and financial reporting expertise and knowledge that qualifies him as a financial expert for his role as a member of the Audit Committee.
Jason H. Downie
Jason H. Downie was appointed to the board of directors of our General Partner in August 2014. Since August 2014, Mr. Downie has also served on the board of directors of Holdings GP. On March 28, 2016, Holdings GP, Holdings and certain of Holdings' subsidiaries filed for bankruptcy. On April 11, 2016, the bankruptcy court confirmed Holdings' plan of reorganization, and on April 13, 2016, Holdings GP, Holdings and Holdings' subsidiaries emerged from bankruptcy.
Mr. Downie serves as Chairman of the Compensation Committee of the board of directors of our General Partner. Mr. Downie has more than 20 years of investment experience and co-founded Tailwater Capital, LLC in January 2013. At Tailwater, Mr. Downie’s primary responsibilities include deal sourcing, transaction execution and monitoring of portfolio companies as well as executive leadership of Tailwater. Prior to co-founding Tailwater, Mr. Downie was a partner with HM Capital Partners, a private equity firm, from August 2000 to December 2012 and served on its investment committee. He joined HM Capital in August 2000 from Rice Sangalis Toole and Wilson, a mezzanine private equity firm, where he was an associate, from June 1999 until August 2000. Prior to Rice Sangalis Toole and Wilson, Mr. Downie was an associate in the equity trading group with Donaldson, Lufkin & Jenrette and was responsible for energy and transportation. Mr. Downie currently serves as a director of TW SWD & Solids Holdco LP, Pivotal Petroleum Partners LP, TSL Holdings I LP, Southcross Holdings GP LLC, Align Midstream Partners LP and Petro Waste Environmental. Mr. Downie received a bachelor’s degree and master’s degree in business administration from The University of Texas at Austin.
Mr. Downie serves as the director designee of Tailwater, one of our Sponsors, as a result of contractual arrangements entered into in connection with the Holdings Transaction. In addition to his affiliation with Tailwater, Mr. Downie was selected to serve as a director due to, his knowledge of the energy industry and his financial and business expertise.
Wallace C. Henderson
Wallace C. Henderson was appointed to the board of directors of our General Partner in August 2014. Since August 2014, Mr. Henderson has also served on the board of directors of Holdings GP. On March 28, 2016, Holdings GP, Holdings and certain of Holdings' subsidiaries filed for bankruptcy. On April 11, 2016, the bankruptcy court confirmed Holdings' plan of reorganization, and on April 13, 2016, Holdings GP, Holdings and Holdings' subsidiaries emerged from bankruptcy.
Mr. Henderson has more than 25 years of energy banking and investment experience. He is currently a managing director and senior member of EIG’s investment team where he oversees the firm’s global investment activities in midstream oil and gas. Prior to joining EIG, Mr. Henderson was a senior financial consultant to Coskata, Inc., an energy technology company from May 2009 until May 2011. Mr. Henderson also spent five years with UBS where he ran the firm’s New York-based energy group and led capital raising and advisory assignments for a wide range of energy companies and sponsors including EIG. Prior to his role with UBS, Mr. Henderson was an energy investment banker at Credit Suisse for 18 years where he specialized in oil and gas project finance, corporate capital raising and mergers and acquisitions for large U.S. and Latin American oil companies. He received a bachelor’s degree in economics from Kenyon College and a master’s in business administration from Columbia University.
Mr. Henderson serves as the director designee of EIG, one of our Sponsors, as a result of contractual arrangements entered into in connection with the Holdings Transaction. In addition to his affiliation with EIG, Mr. Henderson was selected to serve as a director on the board due to his knowledge of the energy industry and his financial and business expertise.
Jerry W. Pinkerton
Jerry W. Pinkerton was appointed as an independent member of the board of directors of our General Partner in April 2012. In addition, Mr. Pinkerton serves as Chairman of the Audit Committee and Chairman of the Conflicts Committee of the board of directors of our General Partner. With respect to the Audit Committee, Mr. Pinkerton qualifies as an "audit committee financial expert." Mr. Pinkerton has over 53 years of management, finance and accounting experience and has held various positions in several publicly traded companies. Mr. Pinkerton has served on the board of directors and as chairman of the audit committee of the general partner of Holly Energy Partners, L.P., a publicly traded master limited partnership that owns and operates petroleum product and crude oil pipeline and terminal, tankage and loading rack facilities, since July 2004. From December 2000 to December 2003, Mr. Pinkerton served as a consultant to TXU Corp. (now Energy Future Holdings Corp.), and, from August 1997 to December 2000, he served as Controller of TXU Corp. and its U.S. subsidiaries. From August 1988 until its merger with TXU Corp. in August 1997, Mr. Pinkerton served as the Vice President and Chief Accounting Officer of ENSERCH Corporation. Prior to joining ENSERCH in August 1988, Mr. Pinkerton was employed for 26 years as an auditor by Deloitte Haskins & Sells, a predecessor firm of Deloitte & Touche, LLP, including 15 years as an audit partner. From May 2008

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to June 2011, Mr. Pinkerton also served on the board of directors of Animal Health International, Inc., an animal health distribution company, where he also served as chairman of its audit committee. Mr. Pinkerton received his bachelor’s degree in accounting from The University of North Texas.
Mr. Pinkerton serves as an independent director designee of our Sponsors as a result of contractual arrangements entered into in connection with the Holdings Transaction. He was appointed due to his audit, accounting and financial reporting expertise and knowledge that qualifies him as a financial expert for his role as the chairman of the Audit Committee. Due to his executive managerial experience with public companies and public accounting firms and his prior board service, including audit committee experience, Mr. Pinkerton possesses business and management expertise and a broad range of expertise and knowledge of board committee functions.
Ronald G. Steinhart
Ronald G. Steinhart was elected as an independent member of the board of directors of our General Partner in January 2013. In addition, Mr. Steinhart serves as a member of the Audit Committee and the Compensation Committee of the board of directors of our General Partner. With respect to the Audit Committee, Mr. Steinhart qualifies as an "audit committee financial expert." Mr. Steinhart retired in 2000 as Chairman and Chief Executive Officer of the Commercial Banking Group of Bank One Corporation (commercial banking), a position he had held since 1996. He has over 37 years of experience in the financial services industry. He led a group of investors that established Team Bank (commercial banking) in 1988 and served as its Chairman and Chief Executive Officer until it merged with Bank One Texas in 1992. He was President and Chief Operating Officer of Bank One Texas through 1996. He is also a former President and Chief Operating Officer of InterFirst Corporation (commercial bank holding company), prior to which he teamed with investors to charter or purchase six other banks. He is also a current director of Penske Automotive Group, Inc. During the last five years, Mr. Steinhart has been a director of Animal Health International, Inc., Susser Holdings Corporation, and Texas Industries Inc., and has been a trustee of the MFS/Compass Group of mutual funds. Mr. Steinhart is an Advisory Board Member of the McCombs School of Business at the University of Texas at Austin. Among the civic positions in which he has served are Chairman of the Board of Trustees of the Teacher Retirement System of Texas, Chairman of the Housing Authority of the City of Dallas, Chairman of the United Way of Metropolitan Dallas, President of the Federal Advisory Council of the Federal Reserve System, Chairman of the Dallas Citizens Council and Regent of the Lamar University System. Mr. Steinhart received his bachelor’s in accounting and his master’s in finance from the University of Texas in Austin.
Mr. Steinhart serves as an independent director designee of our Sponsors as a result of contractual arrangements entered into in connection with the Holdings Transaction. He was appointed due to his management experience, accounting and financial expertise and knowledge. Due to his executive managerial experience and his prior board service, Mr. Steinhart possesses business and management expertise and a broad range of expertise and knowledge of board committee functions.
Bruce A. Williamson
Bruce A. Williamson was elected as an independent member of the board of directors of our General Partner in April 2013. In addition, Mr. Williamson serves as a member of the Audit Committee, Compensation Committee and Conflicts Committee of the board of directors of our General Partner. Most recently, Mr. Williamson was the President and Chief Executive Officer and director of Cleco Corporation, an energy services company, and was the Chairman, President and Chief Executive Officer at Dynegy, Inc. from 2002 through 2011. Prior to his role at Dynegy, Inc., Mr. Williamson was the President and Chief Executive Officer at Duke Energy Global Markets. Prior to Duke, Mr. Williamson was Senior Vice President Finance at PanEnergy and also worked for Shell Oil Company for 14 years in exploration and production in the United States and internationally. Mr. Williamson currently serves on the Board of Directors of Questar Corporation, an integrated natural gas company. Mr. Williamson received his bachelor’s degree in finance from the University of Montana, and his master’s in business administration from the University of Houston.
Mr. Williamson serves as an independent director designee of our Sponsors as a result of contractual arrangements entered into in connection with the Holdings Transaction. He was appointed due to his extensive expertise in the energy industry.
Code of Ethics, Corporate Governance Guidelines and Board Committee Charters
Our General Partner has adopted a Code of Business Conduct and Ethics, which applies to our General Partner's directors, officers and employees. A waiver of the Code of Business Conduct and Ethics for any director or executive officer of our General Partner may be granted only by the Audit Committee, and such committee will report any such waiver to the board of directors of our General Partner. A waiver of the Code of Business Conduct and Ethics for other officers or employees may be granted only by our Chief Executive Officer, who will thereafter report any such waiver to the Audit Committee. The board of directors of our General Partner has also adopted Corporate Governance Guidelines, which outline the important policies and practices regarding our governance. Jerry W. Pinkerton serves as the lead director, as such term is used in the Corporate

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Governance Guidelines. Interested parties may communicate directly with the independent directors by submitting a communication in an envelope marked “Confidential” addressed to the “Independent Members of the Board of Directors” in care of Mr. Pinkerton at 1717 Main Street, Suite 5200, Dallas, Texas 75201.
We make available free of charge, within the "Investors" section of our website at www.southcrossenergy.com, and in print to any unitholder who so requests, our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Audit Committee Charter and Compensation Committee Charter. Requests for print copies may be directed to investorrelations@southcrossenergy.com or to: Investor Relations, Southcross Energy Partners, L.P., 1717 Main Street, Suite 5200, Dallas, Texas 75201, or telephone (214) 979-3720. We will post on our website all waivers to or amendments of the Code of Business Conduct and Ethics, that are required to be disclosed by applicable law and the NYSE's Corporate Governance Listing Standards. The information contained on, or connected to, our website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our General Partner's board of directors and executive officers, and persons who own more than 10% of a registered class of our equity securities, to file with the SEC, and any exchange or other system on which such securities are traded or quoted, initial reports of ownership and reports of changes in ownership of our common units and other equity securities. Officers, directors and greater than 10% unitholders are required by the SEC's regulations to furnish to us and any exchange or other system on which such securities are traded or quoted with copies of all Section 16(a) forms they file with the SEC.
To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that, except as set forth in the following, all reporting obligations of our General Partner's officers, directors and greater than 10% unitholders under Section 16(a) were satisfied during the year ended December 31, 2015.
EIG BBTS Holdings, LLC, EIG Management Company, LLC, EIG Asset Management Company, LLC, EIG Global Energy Partners, LLC, R. Blair Thomas 2010 Irrevocable Trust and R. Blair Thomas jointly filed three late Forms 4 covering six untimely reported transactions in our common units or related derivative securities during the year ended December 31, 2015.
TW BBTS Aggregator LP, BB-II Holdco LP, TW/LM GP Sub, LLC, Tailwater Energy Fund I, LP, TW GP EF-1, LP, TW GP EF-1 GP, LLC, TW GP Holdings, LLC, Tailwater Holdings, LP Tailwater Capital LLC, Jason H. Downie and Edward Herring jointly filed three late Forms 4 covering six untimely reported transactions in our common units or related derivative securities during the year ended December 31, 2015.
Southcross Energy LLC, Southcross Energy Partners GP, LLC, Charlesbank Capital Partners LLC, Charlesbank Equity Fund VI GP, Limited Partnership, Charlesbank Coinvestment Partners Limited Partnership, Charlesbank Equity Fund VI, Limited Partnership, CB Offshore Equity Fund VI LP, Charlesbank Equity Coinvestment Fund VI Limited Partnership, CB-Southcross Holdings, Inc., Southcross Holdings LP, Southcross Holdings GP, LLC, Southcross Holdings Guarantor LP, Southcross holdings Guarantor GP LLC, Southcross Holdings Borrower LP and Southcross Holdings Borrower GP LLC jointly filed one late Form 4 covering four untimely reported transactions in our common units or related derivative securities during the year ended December 31, 2015.
Item 11.
Executive Compensation
Executive Compensation Discussion
Overview of our Executive Compensation Program
This executive compensation discussion describes the compensation policies, programs, material components and decisions of the compensation committee of the board of directors of our General Partner (the “Compensation Committee”) with respect to our General Partner’s executive officers, including the following individuals who are referred to as our “Named Executive Officers”:
John E. Bonn, President and Chief Executive Officer;
Joel D. Moxley, Senior Vice President and Chief Commercial Officer;
Bret M. Allan, Senior Vice President and Chief Financial Officer; and
J. Michael Anderson, former Senior Vice President, Chief Financial Officer and Secretary.

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Our General Partner's compensation practices and programs generally are designed to attract, retain and motivate exceptional leaders and structured to align compensation with our overall performance, including growth in distributions to unitholders. The compensation practices and programs have been implemented to promote achievement of short-term and long-term business objectives consistent with our strategic plans and are applied to reward performance. To accomplish these objectives, the compensation program in 2015 consisted of the following components: (i) base salary, designed to compensate executive officers for work performed during the fiscal year; (ii) short-term incentive compensation, designed to reward executive officers for our yearly performance and for performance specific to an executive officer’s area of responsibility; (iii) long-term incentive compensation in the form of equity awards, meant to align the interests of our executive officers, including our Named Executive Officers, with our long-term performance; and (iv) certain benefits, perquisites, retirement, severance and change in control arrangements.
Our General Partner, under the direction of its board of directors, is responsible for managing our operations and employs all of the employees that operate our business. We reimburse our General Partner, generally on a dollar-for-dollar basis, for the compensation attributable to the work performed on our behalf by its employees for work performed for us. On December 31, 2015, our General Partner had 291 employees who provided direct support to our operations. Certain of those employees provide management, administrative, operational and workforce related services to our affiliates, including Holdings, which owns 100% of our General Partner, and an affiliate of two of our Sponsors.
Effective June 8, 2015, Bret M. Allan became the Senior Vice President and Chief Financial Officer of our General Partner, replacing J. Michael Anderson. Effective June 15, 2015, Mr. Moxley was elected as Senior Vice President and Chief Commercial Officer of our General Partner.
References in this report to Named Executive Officers, executive officers, other officers, directors and employees refer to the Named Executive Officers, executive officers, other officers, directors and employees of our General Partner.
Role of the Compensation Committee and Management
Our General Partner is responsible for the management of us. The Compensation Committee is appointed by the board of directors of our General Partner to assist the board of directors in discharging its responsibilities relating to overall compensation matters, including, without limitation, matters relating to compensation programs for our directors and executive officers. The Compensation Committee is directly responsible for our General Partner’s compensation programs, which include programs that are designed specifically for our executive officers, including our Named Executive Officers.
The Compensation Committee has overall responsibility for evaluating and approving the compensation plans, policies and programs of our General Partner. To that end, the Compensation Committee has the responsibility, power and authority to set the compensation of executive officers, determine grant awards under and administer our General Partner’s equity compensation plans, and assume responsibility for all matters related to the foregoing. The Compensation Committee is charged, among other things, with the responsibility of reviewing the executive officer compensation policies and practices for (i) adherence to our compensation philosophy and (ii) ensuring that the total compensation paid to our executive officers is fair, reasonable and competitive. In 2015, these compensation programs for executive officers consisted of base salary, annual incentive bonus awards and awards under our Amended and Restated 2012 Long-Term Incentive Plan (the “LTIP”), as described below, typically in the form of equity-based restricted units and phantom units, as well as other customary employment benefits. Total compensation of executive officers and the relative emphasis of our main components of compensation are reviewed at least annually by the Compensation Committee, which then makes recommendations to the board of directors of our General Partner for its approval.
It is the practice of the Compensation Committee to meet in person or by conference call at least once a year for a number of purposes. These purposes include (i) assessing the performance of the Chief Executive Officer and other executive officers with respect to our results for the preceding year, (ii) establishing compensation levels for each executive officer for the ensuing year, (iii) determining the amount of the annual bonus pool approved by the board of directors of our General Partner to be paid to the executive officers, after taking into account both the target bonus levels established for those executive officers at the outset of the preceding year and the foregoing performance factors and (iv) determining equity awards under the LTIP for executive officers and other key employees. Our Chief Executive Officer participates in the process of allocating our bonus pool and makes recommendations to the Compensation Committee regarding the amount of bonuses and other compensation paid to executive officers, other than to the Chief Executive Officer.
Compensation Philosophy and Objectives
The principal objective of our compensation program is to attract and retain, as executive officers and employees, individuals of demonstrated competence, experience and leadership in our industry and in those professions required by our business who share our business aspirations, values, ethics and culture.

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In establishing our compensation programs, we consider the following compensation objectives:
to encourage creation of unitholder value;
to reward participants for value creation commensurate with competitive industry standards;
to provide a significant percentage of total compensation that is "at-risk" or variable;
to encourage significant equity ownership to align the interests of executive officers and key employees with those of unitholders;
to provide competitive, performance-based compensation programs that allow us to attract and retain superior talent; and
to develop a strong linkage between business performance, safety, environmental stewardship and employee pay.
We also strive to achieve a fair balance between the compensation rewards that we perceive necessary to remain competitive in the marketplace and fundamental fairness to our unitholders, taking into account the return on their investment.
In measuring the contributions of our executive officers to the performance of us for 2015, the Compensation Committee considered and utilized the following financial and operating performance factors:
Adjusted EBITDA reported by us;
completion of a business acquisition or transaction to enhance scale, stability and access to capital;
processed gas volumes associated with our South Texas assets;
achievement of our safety goals;
costs, completion dates and operational milestones associated with the execution of our organic growth plans;
our capital expenditures and operating expenses; and
success in executing contracts.
Compensation Methodology
The Compensation Committee intends to review annually our executive compensation program in total and each element of compensation specifically. The Compensation Committee intends to include the following in its periodic review of our executive compensation program: (i) an analysis of the compensation practices of other companies in our industry; (ii) the competitive market for executive talent; (iii) the evolving demands of our business; (iv) specific challenges that we may face; and (v) individual contributions to us. The Compensation Committee will recommend to the board of directors of our General Partner adjustments to the overall executive compensation program, and to its individual components, as the Compensation Committee determines necessary to achieve our goals and comply with the Compensation Committee’s compensation philosophy. The Compensation Committee utilizes compensation consultants periodically to assist in its review of, and to provide input regarding, our compensation program and its elements.
Actual compensation decisions for individual officers are the result of the Compensation Committee’s subjective analysis of a number of factors, including the individual officer’s experience, skills or tenure with us and changes to the individual’s position. Each executive’s current and prior compensation is considered in setting future compensation. The amount of each executive’s current compensation is considered as a base-line against which the Compensation Committee makes determinations as to whether adjustments are necessary to retain the executive in light of competition or in order to provide continuing performance incentives. Thus, the Compensation Committee’s determinations regarding compensation are the result of the exercise of judgment based on all reasonably available information and, to that extent, are discretionary. The Compensation Committee may use its discretion to adjust any of the components of compensation to achieve our goal of attracting and retaining individuals with the skills necessary to execute our business strategy and to develop and grow our business.

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Elements of our Compensation Programs
Compensation for our Named Executive Officers consists primarily of the elements, and their corresponding objectives, identified in the following table:
Compensation Element
 
Characteristics
 
Primary Objectives
Base salary
 
Fixed annual cash compensation. Salaries may be increased periodically based on performance or other factors.
 
Recognize performance of job responsibilities and attract and retain individuals with superior talent.
Annual performance-based compensation
 
Performance-related annual cash incentives earned based on financial and other objectives.
 
Promote near-term performance objectives and reward individual contributions for the achievement of those objectives.
Long-term equity participation
 
Equity awards purchased or granted subject to time and/or performance based vesting restrictions intended to align indirect ownership interests of Named Executive Officers with unitholder interests.
 
Emphasize long-term performance objectives, encourage the maximization of unitholder value and retain key executives by providing an opportunity to participate in our ownership. Vesting restrictions are designed to facilitate Named Executive Officer retention and to provide continuing performance incentives.
Long-term cash incentives
 
In 2016, long-term cash incentives granted subject to time vesting restrictions provide long-term compensation, other than equity compensation.

 
Long-term cash incentive with vesting restrictions are designed to facilitate Named Executive Officer retention.

Health and welfare benefits
 
Health and welfare benefits (medical, dental, vision, disability insurance and life insurance) are available for Named Executive Officers, our executive officers and all other regular full-time employees.

 
Provide benefits to meet the health and wellness needs of our Named Executive Officer, executive officers and other employees, and their families.

Retirement savings 401(k) plan
 
Qualified 401(k) retirement plan benefits are available for our Named Executive Officers, other executive officers, and all other regular full-time employees. For 2015, we matched employee contributions to 401(k) plan accounts up to a maximum employer contribution of 6% of the employee's eligible compensation, subject to the annual maximum contribution limit imposed by the Internal Revenue Service.
 
Provide an opportunity for tax-efficient savings.
Severance and change in control benefits
 
Severance agreements or employment agreements provide for base salary and benefit continuation in the event of certain terminations of employment. A portion of our Named Executive Officers’ equity incentives and long-term cash incentives are subject to accelerated change in control vesting.
 
Encourage the continued attention and dedication of our Named Executive Officers and focus their attention when considering strategic alternatives.

Compensation Components and Analysis
Base Salary. We believe that executive officer base salaries should be competitive with salaries for executive officers in similar positions with similar responsibilities in our marketplace.

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The base salaries for our Named Executive Officers as of December 31, 2015 are set forth in the following table:
Name and Principal Position
 
Base Salary
John E. Bonn (1)
 
$
450,000

President and Chief Executive Officer
 
 
Joel D. Moxley (2)
 
$
385,000

Senior Vice President and Chief Commercial Officer
 
 
Bret M. Allan (3)
 
$
300,000

Senior Vice President and Chief Financial Officer
 
 
J. Michael Anderson (4)
 
$
325,000

Former Senior Vice President and Chief Financial Officer and Secretary
 
 
(1) In January 2015, Mr. Bonn's base salary was increased from $351,000 to $450,000 to reflect his election as our Chief Executive Officer. Effective March 5, 2016, Mr. Bonn's salary was increased to $500,000.
(2) In January 2015, Mr. Moxley was elected as Senior Vice President and Chief Commercial Officer of our General Partner. Effective March 14, 2016, Mr. Moxley's salary was increased to $397,000.
(3) On June 8, 2015, Mr. Allan was elected as Senior Vice President and Chief Financial Officer of our General Partner. Effective March 14, 2016, Mr. Allan's salary was increased to $330,000.
(4) On June 8, 2015, Mr. Anderson announced his departure from the Partnership and is no longer an officer of our General Partner. See our Current Reports on Form 8-K, filed with the SEC on June 8, 2015 and July 8, 2015 regarding the departure of Mr. Anderson from our General Partner.
Going forward, base salaries for our Named Executive Officers will continue to be reviewed periodically by the Compensation Committee, with adjustments expected to be made generally in accordance with the considerations described above and to maintain base salaries at competitive levels.
Annual Performance-Based Compensation.  Each of our Named Executive Officers participates in an incentive bonus compensation program under which incentive awards are determined annually.
For 2015, the board of directors of our General Partner awarded discretionary bonuses based upon factors such as the financial and operational performance of our assets, capital expenditure and operating expense performance, development of growth projects, increase in new gas supply contracts, processed gas volumes, achievement of safety goals and each individual’s contributions to our overall success during the year.
Long-Term Equity Participation. Please see the sections following our Summary Compensation Table (as defined below) for discussion regarding the long-term equity compensation granted to our Named Executive Officers.

Long-Term Cash Incentive. Please see the sections following our Summary Compensation Table for discussion regarding the long-term cash compensation granted to our Named Executive Officers.
Benefit Plans, Perquisites and Retirement.  We provide our executive officers, including our Named Executive Officers, with a standard complement of health and retirement benefits under the same plans as all other employees, including medical, dental and vision benefits, disability and life insurance coverage, and a defined contribution plan that is tax-qualified under Section 401(k) of the Internal Revenue Code (the “401(k) Plan”). We believe that our health benefits provide stability to our Named Executive Officers, thus enabling them to better focus on their work responsibilities, while our 401(k) Plan provides a vehicle for tax-preferred retirement savings with additional compensation in the form of an employer match that adds to the overall desirability of our executive compensation package. For 2015, we provided an employer match under our 401(k) Plan equal to 100% of employee contributions up to 6% of eligible compensation, subject to the annual maximum contribution limit imposed by the Internal Revenue Service. None of our Named Executive Officers participated in any defined benefit pension plans or non-qualified deferred compensation plans.
Severance Agreements and Change in Control Provisions.    We maintain severance and other compensatory agreements with our executive officers for a variety of reasons, including the fact that severance agreements can be an important recruiting tool in the market in which we compete for talent. Certain provisions in some of these agreements, such as confidentiality, non-solicitation and non-compete clauses, protect us and our unitholders after the termination of the employment relationship. We

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believe that it is appropriate to compensate former executives for these post-termination agreements, and that compensation helps to enhance the enforceability of these arrangements. These agreements are described in more detail below.
Retention Agreements.    In 2016, we entered into retention agreements with our Named Executive Officers. These retention agreements award a cash incentive to retain our talent. These agreements are described in more detail below.
Recoupment Policy.    Equity awards granted under the LTIP are subject to recovery, including modification and forfeiture, for certain “Act[s] of Misconduct” as defined in the LTIP. We currently do not have a recovery policy applicable to annual cash incentive bonuses, if any are awarded. The Compensation Committee will continue to evaluate the need to amend such a policy, in light of current legislative policies, and economic and market conditions.
Compensation Committee Report
The Compensation Committee issued the following report:
We have reviewed and discussed with management certain compensation discussion provisions to be included in our Annual Report on Form 10-K for the year ended December 31, 2015 to be filed pursuant to Section 13(a) of the Securities and Exchange Act of 1934 (the “Annual Report”). Based on those reviews and discussions, we recommend to the Board of Directors of the General Partner that the Executive Compensation Discussion be included in the Annual Report.
Compensation Committee
Jason H. Downie, Chairman
Jon M. Biotti
Bruce A. Williamson
Ronald G. Steinhart
Compensation Committee Interlocks and Insider Participation
During the year ended December 31, 2015, the Compensation Committee was comprised of Messrs. Biotti (Chairman), Williamson and Steinhart. No member of the Compensation Committee was an officer or employee of our General Partner. Mr. Biotti is affiliated with Charlesbank, which controls Southcross Energy LLC. Jason Downie was appointed to the Compensation Committee on February 2, 2016. Mr. Downie is affiliated with Tailwater. See Part III, Item 10 and Item 13 of this Annual Report.
2015 Summary Compensation Table
The following table (the "Summary Compensation Table") sets forth certain information with respect to the compensation paid to our Named Executive Officers for the years ended December 31, 2014 and 2015:
Name and Principal Position
Year
 
Salary ($)
 
Bonus($)(1)
 
Stock
awards
($)(2)
 
All other
compensation
($)(3)
 
Total
($)
John E. Bonn
2015
 
446,193

 
350,000

 
904,391

 
210,933

 
1,911,517

President and Chief Executive Officer
2014
 
283,500

 

 
1,854,560

 
64,710

 
2,202,770

Joel D. Moxley (4)
2015
 
199,904

 
160,000

 
490,500

 
12,040

 
862,444

Senior Vice President and Chief Commercial Officer
2014
 

 

 

 

 

Bret M. Allan (5)
2015
 
161,538

 
265,000

 
392,400

 
9,239

 
828,177

Senior Vice President and Chief Financial Officer
2014
 

 

 

 

 

J. Michael Anderson (6)
2015
 
173,233

 
325,000

 
146,250

 
1,195,426

 
1,839,909

Senior Vice President and Chief Financial Officer
2014
 
319,231

 

 
1,383,462

 
1,168,600

 
2,871,293

_______________________________________________________________________________
(1)
For 2015, represents bonus awards earned for performance in 2015 and paid on February 26, 2016. For 2015, also includes a $325,000 retention payment paid to Mr. Anderson and a $40,000 initial reporting bonus paid to Mr. Allan.
(2)
For 2015, represents the grant date fair value of LTIP awards for Messrs. Bonn, Biegler and Anderson based on the closing price on March 10, 2015 of $13.63 and the grant date fair value of LTIP awards for Messrs. Moxley and Allan on July 1, 2015 of $10.90. For assumptions used in determining the fair value of stock awards, see Note 13 to the consolidated financial statements.

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(3)
For 2015, Mr. Bonn had a 401(k) match of $18,000, reimbursement for interim living and relocation expenses of $192,249. For 2015, Mr. Moxley had a 401(k) match of $11,698. For 2015, Mr. Allan had a 401(k) match of $8,897. For 2015, Mr. Anderson had a 401(k) match of $10,394, a severance payment of $1,172,774 and reimbursement for interim living expenses of $11,859. For 2015, also includes life insurance premiums for Messrs. Bonn, Moxley, Allan and Anderson.
(4)
Mr. Moxley became employed by our General Partner on June 15, 2015. See our Current Report on Form 8-K, filed with the SEC on June 15, 2015 regarding the election of Mr. Moxley to our General Partner.
(5)
Mr. Allan became employed by our General Partner on June 8, 2015. See our Current Report on Form 8-K, filed with the SEC on June 8, 2015 regarding the election of Mr. Allan to our General Partner.
(6)
On June 8, 2015, Mr. Anderson announced his departure from the Partnership and is no longer an officer of our General Partner. See our Current Reports on Form 8-K, filed with the SEC on June 8, 2015 and July 8, 2015 regarding the election of Mr. Anderson from our General Partner.
A discussion of the material compensation information disclosed in the Summary Compensation Table is set forth in the "Compensation Components and Analysis" section above and following is a discussion of other material factors necessary to understanding the total compensation afforded to our Named Executive Officers:
Named Executive Officer LTIP Units. On March 10, 2015, the board of directors of our General Partner granted 66,353 phantom units to Mr. Bonn (14,537 of which vest on the first anniversary of the grant date and 51,816 of which vest in three cumulative annual installments on the anniversary of the grant date) and 10,730 phantom units to Mr. Anderson (all of which have vested in connection with Mr. Anderson’s departure from our General Partner). On July 1, 2015, the board of directors of our General Partner granted 45,000 phantom units to Mr. Moxley (all of which vest in three cumulative annual installments on the anniversary of the grant date) and 36,000 phantom units to Mr. Allan (all of which vest in three cumulative annual installments on the anniversary of the grant date).
Except for the LTIP awards with one-year vesting as indicated above, the phantom units awarded to our Named Executive Officers vest in three cumulative annual installments, with one-third of the units vesting on each anniversary of the grant date, subject to continued employment through the applicable vesting date. Each phantom unit granted to our Named Executive Officers in 2015 was granted in tandem with corresponding distribution equivalent rights (which are discussed below). Generally, upon the grantee’s cessation of employment, all phantom units that have not vested will be forfeited. Phantom units will vest in full upon a cessation of service due to death or disability or upon a change in control. For future information regarding phantom units, see “Summary Compensation Table - Restricted Units and Phantom Units” below.
In connection with Mr. Anderson’s departure from our General Partner, Mr. Anderson entered into a General Release Agreement with the General Partner (the “Release Agreement”) effective June 26, 2015, which accelerated the vesting of 38,997 of the phantom units previously issued to Mr. Anderson under the LTIP. See our Current Reports on Form 8-K, filed with the SEC on June 8, 2015 and July 8, 2015 regarding the departure of Mr. Anderson from our General Partner.
Amended and Restated Long-Term Incentive Plan.  Under our LTIP, certain officers (including our Named Executive Officers), employees and directors are eligible to receive awards with respect to our equity interests, thereby linking the recipients’ compensation directly to our performance. The description of the LTIP set forth below is a summary of the material features of the LTIP. This summary does not purport to be a complete description of all of the provisions of the LTIP.
On October 28, 2015, the board of directors of our General Partner unanimously approved the Amended and Restated 2012 Long-Term Incentive Plan (the “Amended LTIP”), which is substantially similar to our 2012 Long Term Incentive Plan (the “2012 Plan”). Effective as of December 7, 2015, the unitholders holding a majority of the Partnership’s outstanding limited partnership units approved the Amended LTIP by written consent in lieu of a special meeting of unitholders. The Amended LTIP increased the number of Partnership common units that may be granted as awards from 1,750,000 to 6,250,000 (inclusive of the 1,750,000 common units authorized under our 2012 LTIP), with such amount subject to adjustment as provided for under the terms of the Amended LTIP if there is a change in the common units, such as a unit split or other reorganization. The Amended LTIP also extended the term of the LTIP to a period of 10 years following its adoption. The term LTIP, as used in this Annual Report, means the 2012 LTIP as amended by the Amended LTIP. The LTIP awards granted to the Named Executive Officers in 2015 were granted prior to the adoption of the Amended LTIP.
The LTIP provides for the grant, from time to time at the discretion of the board of directors of our General Partner or the Compensation Committee, of restricted units, phantom units, unit options, distribution equivalent rights and other unit-based awards. Pursuant to the LTIP and subject to further adjustment in the event of certain transactions or changes in capitalization, an aggregate 6,250,000 common units may be delivered pursuant to awards under the LTIP.

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Units that are canceled or forfeited will be available for delivery pursuant to other awards. The LTIP is administered by the board of directors of our General Partner, although such administration function may be delegated to a committee (including the Compensation Committee) that may be appointed by the board of directors of our General Partner to administer the LTIP. The LTIP is designed to promote our interests, as well as the interests of our unitholders, by rewarding our directors, officers and employees for delivering desired performance results, as well as by strengthening our ability to attract, retain and motivate qualified individuals to serve as our directors, officers and employees.
Restricted Units and Phantom Units.  A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. The administrator of the LTIP may make grants of restricted and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the administrator may determine are appropriate, including the period over which restricted or phantom units will vest. The administrator of the LTIP may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change in control (as defined in the LTIP) or as otherwise described in an award agreement.
Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units. The administrator of the LTIP, in its discretion, may also grant tandem distribution equivalent rights with respect to phantom units. Distribution equivalent rights are rights to receive an amount, in cash, units, restricted units and/or phantom units, equal in value to the distributions made on units during the period an award remains outstanding.
Unit Options.  The LTIP also permits the grant of options covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit options may be granted to such eligible individuals and with such terms as the administrator of the LTIP may determine, consistent with the LTIP; however, a unit option must have an exercise price equal to at least the fair market value of a common unit on the date of grant (except under certain circumstances).
Other Unit-Based Awards.  The LTIP also permits the grant of "other unit-based awards," which are awards that, in whole or in part, are valued or based on or related to the value of a unit.
The vesting of an “other unit-based award” may be based on a participant's continued service, the achievement of performance criteria or other measures. On vesting or on a deferred basis upon specified future dates or events, an "other unit-based award" may be paid in cash and/or in units (including restricted units), as the administrator of the LTIP may determine.
Source of Common Units; Cost.  Common units to be delivered with respect to awards may be newly-issued units, common units acquired by us or our General Partner in the open market, common units already owned by our General Partner or us, common units acquired by our General Partner directly from us or any other person or any combination of the foregoing. With respect to awards made to employees of our General Partner, our General Partner will be entitled to reimbursement by us for the cost incurred in acquiring such common units or, with respect to unit options, for the difference between the cost it incurs in acquiring these common units and the proceeds it receives from an optionee at the time of exercise of an option. Thus, we will bear the cost of all awards under the LTIP. If we issue new common units with respect to these awards, the total number of common units outstanding will increase, and our General Partner will remit the proceeds it receives from a participant, if any, upon exercise of an award to us. With respect to any awards settled in cash by our General Partner, our General Partner will be entitled to reimbursement by us for the amount of the cash settlement.
Amendment or Termination of LTIP.  The administrator of the LTIP, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The LTIP will automatically terminate on the tenth anniversary of the date of the adoption of the Amended LTIP (as described above). The administrator of the LTIP also will have the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would impair materially the rights of the participant without the consent of the affected participant, and/or result in taxation to the participant under the Internal Revenue Code Section 409A.
2016 Cash-Based Long-Term Incentive Plan.  On March 11, 2016, the board of directors of our General Partner approved the 2016 Cash-Based Long-Term Incentive Plan (the “2016 Cash LTIP”). The description of the 2016 Cash LTIP set forth below is a summary of the material features of the 2016 Cash LTIP. This summary does not purport to be a complete description of all of the provisions of the 2016 Cash LTIP.
The 2016 Cash LTIP provides for the grant, from time to time, of cash awards to certain of our employees. The 2016 Cash LTIP is administered by the board of directors of our General Partner, although such administration function may be delegated to a committee (including the Compensation Committee) comprised solely of two or more nonemployee directors. The 2016 Cash LTIP is designed to promote our interests by strengthening our ability to retain and motivate our employees.

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Awards Under 2016 Cash LTIP.  Awards under the 2016 Cash LTIP (each, a “2016 Cash LTIP Award”) are determined by the Board or the Compensation Committee and are subject to the vesting of the cash award upon specified future dates. A third of each 2016 Cash LTIP Award will vest on each of April 1, 2017, April 1, 2018, and April 1, 2019, subject to continued employment through the applicable vesting date. Generally, upon the grantee’s cessation of employment, any cash awarded pursuant to a 2016 Cash LTIP Award that has not vested will be forfeited. However, if the employee is terminated without cause (as defined in the LTIP), then such employee is entitled to receive the portion of the 2016 Cash LTIP Award that would have been payable on the next vesting date, but shall forfeit any further unvested 2016 Cash LTIP Award. A 2016 Cash LTIP Award shall vest in full, subject to continued employment through the certain event, upon a termination due to death or disability (as defined in the LTIP) or a change of control (as defined in the 2016 Cash LTIP).
Amendment or Termination of 2016 Cash LTIP.  The Board or the Compensation Committee may amend or terminate any 2016 Cash LTIP Award or the 2016 Cash LTIP in its discretion provided that any amendment or termination adverse to any employee under the 2016 Cash LTIP requires the consent of such employee. The 2016 Cash LTIP shall terminate on the date that all awards are paid.
2016 Cash LTIP Awards.  On April 12, 2016, the board of directors of our General Partner awarded our Named Executive Officers cash awards under the 2016 Cash LTIP. The 2016 Cash LTIP Awards are not reflected in the Summary Compensation Table because they were not awarded as compensation earned for performance in 2015.
The 2016 Cash LTIP Awards are as follows:
Name
 
Award Value
John E. Bonn (1)
 
$
900,000

Joel D. Moxley (1)
 
$
480,000

Bret M. Allan (1)
 
$
390,000

(1) For Messrs. Bonn, Moxley, and Allan, a third of each of their 2016 Cash LTIP Award will vest on each of April 1, 2017, April 1, 2018, and April 1, 2019, subject to continued employment through the applicable vesting date.
Retention Agreements.  On March 17, 2016, our General Partner entered into retention agreements (the “Retention Agreements”) with Messrs. Bonn, Moxley and Allan. Any payments under the Retention Agreements are not reflected in the Summary Compensation Table because they will not be awarded as compensation earned for performance in 2015. The description of the Retention Agreements set forth below is a summary of the material features of the Retention Agreements. This summary does not purport to be a complete description of all of the provisions of the Retention Agreements.
Pursuant to the Retention Agreements, Messrs. Bonn, Moxley and Allan will each receive a one-time special restructuring bonus in an amount equal to 100% of his then-current annual salary (the “Restructuring Bonus”) if he remains continuously employed with our General Partner through the date that Holdings consummates a plan of reorganization under Chapter 11 of Title 11 of the United States Code. Messrs. Bonn, Moxley and Allan also will receive a special one-time retention bonus in an amount equal to 100% of his then-current annual salary (the “Retention Bonus”) if he remains continuously employed with our General Partner through November 1, 2016.
If there is a change in control (as such term is defined in the LTIP), the officer is terminated without cause (as defined in each officer’s applicable employment or severance agreement), or the officer resigns for good reason (as defined in each officer’s applicable employment or severance agreement) on or after March 16, 2016, but prior to November 1, 2016, such officer will be entitled to receive any unpaid portion of the Restructuring Bonus or the Retention Bonus, subject to such officer’s execution of a general release of claims (if terminated without cause or resigned for good reason).
All Other Compensation.  Please see the discussions above for a discussion of the base salaries, short- and long-term incentive compensation, benefits, perquisites and retirement arrangements paid or made available to our Named Executive Officers. Please also see the section below entitled “Outstanding Equity Awards at December 31, 2015” for a discussion of outstanding equity awards and the section below entitled “Potential Payments Upon a Termination or Change in Control” for a discussion of payments made upon termination of employment and certain change in control events.


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Outstanding Equity Awards at December 31, 2015
Southcross Energy Partners, L.P. Equity Awards. The following table provides information regarding LTIP units held by our Named Executive Officers as of December 31, 2015:
 
Southcross Energy Partners, L.P. - LTIP Units
Name
Number of time-vesting units that have not vested
 
Fair value of time-vesting units that have not vested(1)
John E. Bonn
66,353

(2)
$
236,217

Joel D. Moxley
45,000

(3)
$
160,200

Bret M. Allan
36,000

(4)
$
128,160

J. Michael Anderson (5)

 
$

__________________________________________________________________________________________ 
(1)
Amounts were calculated based on the closing price per common unit on December 31, 2015 of $3.56.
(2)
Represents the number of unvested time vesting LTIP units awarded to Mr. Bonn on March 10, 2015, subject to his continued employment through the applicable vesting date. The 51,816 units vest (on a one for one basis) in three cumulative annual installments on the anniversary of the grant date and 14,537 phantom units vest (on a one for one basis) on the first anniversary of the grant date. 31,809 phantom units of the 66,353 phantom units owned by Mr. Bonn vested on March 10, 2016.
(3)
Represents the number of unvested time vesting LTIP units awarded to Mr. Moxley on July 1, 2015, subject to his continued employment through the applicable vesting date. The units vest (on a one for one basis) in three cumulative annual installments on the anniversary of the grant date.
(4)
Represents the number of unvested time vesting LTIP units awarded to Mr. Allan on July 1, 2015, subject to his continued employment through the applicable vesting date. The units vest (on a one for one basis) in three cumulative annual installments on the anniversary of the grant date.
(5)
On June 8, 2015, Mr. Anderson announced his departure from the Partnership and is no longer an officer of our General Partner. Effective as of June 26, 2015, Mr. Anderson entered into the Release Agreement with the General Partner, which accelerated the vesting of 38,997 phantom units previously issued to Mr. Anderson under the LTIP. See our Current Reports on Form 8-K, filed with the SEC on June 8, 2015 and July 8, 2015 regarding the departure of Mr. Anderson from our General Partner.
Potential Payments Upon a Termination or Change in Control
Severance and Change in Control Benefits.  Our Named Executive Officers are entitled to severance payments and benefits upon certain terminations of employment and, in certain cases, upon a change in control. In addition, Mr. Anderson was entitled to severance payments and benefits upon certain qualifying terminations of employment (including in connection with a change in control) and, in certain cases, upon a change in control.
Messrs. Anderson, Moxley and Allan entered into severance agreements with our General Partner that provide for severance benefits upon certain terminations of employment. Mr. Bonn has entered into an employment agreement with our General Partner that provides for severance benefits upon certain terminations of employment.
Mr. Anderson's Retention Agreement.  Effective November 2014, Mr. Anderson entered into a retention agreement with our General Partner providing for the payment to Mr. Anderson of $325,000 after the timely filing of our Annual Report on Form 10-K for the fiscal year ended December 31, 2014 and his continued employment as of May 1, 2015 (other than by reason of an involuntary termination by the Company without cause or a resignation for good reason). The retention payment was made to Mr. Anderson on June 12, 2015.
Mr. Anderson's Severance Benefits.  On June 8, 2015, Mr. Anderson announced his departure from the Partnership and is no longer an officer of our General Partner. Mr. Anderson entered into the Release Agreement with our General Partner that became effective as of June 26, 2015 (the “Release Agreement Effective Date”).

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Under the Release Agreement, Mr. Anderson received (i) his base salary through the Release Agreement Effective Date, (ii) the pro rata portion of the target bonus for the current year through the Release Agreement Effective Date, which equaled $94,562, (iii) a bonus payment of $390,000, (iv) a severance payment of $650,000 and (v) reimbursement for the cost of COBRA coverage for 18 months. In addition, the Release Agreement required the Partnership to accelerate the vesting of 38,997 phantom units previously issued to Mr. Anderson under the LTIP, and provided for the payment of accumulated distribution equivalent rights with respect to such phantom units in the amount of $38,212. The Release Agreement includes a general release of claims by Mr. Anderson and customary restrictive covenants.
Mr. Bonn's Severance and Change in Control Benefits. On March 5, 2015, our General Partner entered into an employment agreement with John E. Bonn, the President and Chief Executive Officer of our General Partner (the “Bonn Employment Agreement”). The Bonn Employment Agreement provides for an initial three-year term, unless earlier terminated. The Bonn Employment Agreement automatically extends for one year periods unless notice is given otherwise prior to the expiration of the then-current term. Mr. Bonn is entitled to receive an annual base salary of $450,000 for the first year, $500,000 for the second year and not less than $500,000 for each year thereafter, as determined by the board of directors of our General Partner. Mr. Bonn may receive an annual cash bonus based on annual performance targets in an amount determined by the board of directors of our General Partner in its discretion with a target annual bonus equal to Mr. Bonn’s salary for such year. In 2015, Mr. Bonn received a grant of LTIP awards with a fair market value of $904,391. Mr. Bonn may also receive LTIP awards as determined by the board of directors of our General Partner. Mr. Bonn is also entitled to receive certain benefits and reimbursement of certain expenses, including relocation expenses.
Under the Bonn Employment Agreement, upon a termination of Mr. Bonn’s employment by us without “cause” or by Mr. Bonn for “good reason,” Mr. Bonn will be entitled to receive (i) an amount equal to two times his then‑current annual base salary, (ii) an amount equal to two times his target annual bonus, (iii) an amount equal to the cost of COBRA coverage for 18 months after termination and (iv) an amount equal to $150,000 if terminated during the first year, $100,000 if terminated during the second year or $50,000 if terminated during the third year (and no additional payment if Mr. Bonn is terminated after the third year). The severance payment is subject to Mr. Bonn’s execution of a general release agreement and compliance with certain restrictions.
A for “cause” termination would occur under the Bonn Employment Agreement if Mr. Bonn (i) fails to perform satisfactorily his material duties or to devote his full time and effort to his position, (ii) violates any material company policy that remains un-remedied after reasonable notice to cure the violation, (iii) fails to follow lawful directives from our Chairman or the board of directors of our General Partner, (iv) his negligence or material misconduct, (v) his fraud, embezzlement, misappropriation, material misconduct, conversion of assets or breach of fiduciary duty or (vi) any felony conviction.
A “good reason” termination would be permitted under Mr. Bonn’s employment within 90 days after the following occurs (without Mr. Bonn’s written consent): (i) Mr. Bonn is removed as Chief Executive Officer, (ii) a material diminution of his base salary or (iii) a change in the location of Mr. Bonn’s employment that requires Mr. Bonn to relocate his residence to a location more than 50 miles from Dallas, Texas.
During his employment and for one year following his termination, Mr. Bonn is subject to certain non-competition and non-solicitation provisions set forth in the Bonn Employment Agreement. Mr. Bonn is also subject to certain confidentiality provisions during and after his employment.
With regard to Mr. Bonn’s LTIP phantom unit awards, upon certain transactions generally resulting in a change in control of our General Partner or Partnership or cessation of his services due to death or disability, any unvested phantom units will vest in full. For additional information regarding the vesting of the phantom units, see the discussion under the Summary Compensation Table above.
With regard to Mr. Bonn’s 2016 Cash LTIP Award, if Mr. Bonn is terminated without cause (as defined in the LTIP), then Mr. Bonn is entitled to receive the portion of the 2016 Cash LTIP Award that would have been payable on the next vesting date, but shall forfeit any further unvested 2016 Cash LTIP Award. A 2016 Cash LTIP Award shall vest in full, subject to continued employment through the certain event, upon a termination due to death or disability (as defined in the LTIP) or a change of control (as defined in the 2016 Cash LTIP). For additional information regarding the vesting of Mr. Bonn’s 2015 Cash LTIP Award, see the discussion under the Summary Compensation Table above.
Mr. Moxley's Severance and Change in Control Benefits. Under Mr. Moxley's severance agreement, dated as of June 15, 2015, upon termination of Mr. Moxley’s employment by us within 12 months following a sale event (as defined in the severance agreement), termination without “cause” or by Mr. Moxley for “good reason,” Mr. Moxley is entitled to receive (i) base salary through the date of termination, (ii) an amount equal to two times his target annual bonus, (iii) an amount equal to two times his then-current annual base salary and (iv) an amount equal to the cost of COBRA coverage for 18 months after termination. Additionally, severance payments are conditioned upon the execution of a general release of claims and continued

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compliance with certain non-solicitation restrictions for twelve months following termination and certain confidentiality provisions.
A for “cause” termination would occur under Mr. Moxley’s severance agreement if Mr. Moxley (i) fails to satisfactorily perform his material duties or to devote his full time and effort to his position, (ii) violates any material company policy that remains un-remedied after reasonable notice to cure the violation, (iii) fails to follow lawful directives from our Chairman, President and Chief Executive Officer, the board of directors of our General Partner or Mr. Moxley’s direct supervisor, (iv) his negligence or material misconduct, (v) his dishonesty or fraud or (vi) any felony conviction.
A “good reason” termination would be permitted under Mr. Moxley’s severance agreement if: (i) there is material change in Mr. Moxley’s job duties and responsibilities, (ii) a material diminution of his base salary unless the reduction applies to all employees of the General Partner employed at similar levels or (iii) a change in the location that Mr. Moxley regularly works of more than 25 miles.
With regard to Mr. Moxley’s LTIP phantom unit awards, upon certain transactions generally resulting in a change in control of our General Partner or Partnership or cessation of his services due to death or disability, any unvested phantom units will vest in full. For additional information regarding the vesting of the phantom units, see the discussion under the Summary Compensation Table above.
With regard to Mr. Moxley’s 2016 Cash LTIP Award, if Mr. Moxley is terminated without cause (as defined in the LTIP), then Mr. Moxley is entitled to receive the portion of the 2016 Cash LTIP Award that would have been payable on the next vesting date, but shall forfeit any further unvested 2016 Cash LTIP Award. A 2016 Cash LTIP Award shall vest in full, subject to continued employment through the certain event, upon a termination due to death or disability (as defined in the LTIP) or a change of control (as defined in the 2016 Cash LTIP). For additional information regarding the vesting of Mr. Moxley’s 2015 Cash LTIP Award, see the discussion under the Summary Compensation Table above.
Mr. Allan's Severance and Change in Control Benefits. Mr. Allan's Severance Agreement, dated as of June 8, 2015, has the same terms as Mr. Moxley's Severance Agreement, described above.
Mr. Allan also has the same vesting as Mr. Moxley and Mr. Bonn in regards to LTIP phantom unit awards and 2016 Cash LTIP Awards.
Director Compensation
Officers, employees or paid consultants of our General Partner who also serve as directors do not receive additional compensation for their service as directors. On April 12, 2016, the board of directors of our General Partner and the Compensation Committee revised our Southcross Energy Partners GP, LLC Non-Employee Director Compensation Arrangement. In 2015, our directors who are not officers, employees or paid consultants of our General Partner received a combination of cash and common units to be granted pursuant to the LTIP as compensation for attending meetings of our board of directors of our General Partner and any committees thereof. In 2016, our directors who are not officers, employees or paid consultants of our General Partner may be awarded only cash compensation.
For 2016, our General Partner awarded $75,000 in cash to the directors who are not officers, employees or paid consultants of our General Partner. Such directors were not awarded an equity grant. Cash awards awarded in 2016 are not reflected in the director compensation table below because they were not compensation earned for service in 2015.
Specifically, directors were eligible for the following in 2015:
i.
An annual retainer of $50,000, to be paid quarterly in arrears;
ii.
An annual retainer of $10,000 for the Chairperson of the Audit Committee, to be paid quarterly in arrears;
iii.
An annual retainer of $5,000 for the Chairperson of the Compensation Committee, to be paid quarterly in arrears;
iv.
An annual retainer of $2,500 for the Chairperson of the Conflicts Committee, to be paid quarterly in arrears;
v.
$1,500 for each board meeting attended (whether in person or telephonically);
vi.
$1,200 for each committee (Audit, Compensation or Conflicts) meeting attended (whether attended in person or telephonically);
vii.
A per diem amount for assistance with special projects, in an amount commensurate with the amount payable for attendance at Board or Committee meetings; and

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viii.
An annual equity grant of common units from us pursuant to the LTIP equivalent to $75,000 divided by the average of the closing daily sales price of our common units for the ten trading days immediately prior to April 1st of each year. (However, in 2016, the directors are only eligible for a lump sum of payment of $75,000 instead of an equity grant).
Pursuant to the Non-Employee Director Compensation Arrangement, compensation for directors who serve for only a portion of a year is pro-rated for time served. Our non-employee directors are reimbursed for certain expenses incurred for their services to us.
We have adopted the Southcross Energy Partners, L.P. Non-Employee Director Deferred Compensation Plan, pursuant to which non-employee directors of our general partner may elect on an annual basis to defer all earned cash and/or equity compensation until the director is no longer a director of our general partner. All amounts deferred will be converted into phantom units from us, which will be entitled to receive quarterly distributions from us. These quarterly distributions will also be converted to phantom units. At the conclusion of the deferral period, the accrued phantom units will be paid to the director in the form of (i) cash for deferrals of cash compensation equal to the fair market value as of such date and (ii) common units for deferrals of equity compensation. For the calendar year 2015, Mr. Williamson has elected to defer his non-employee director compensation.
Mr. Biotti informed us that in accordance with the internal policies of Charlesbank and the terms of the limited partnership agreements for the Charlesbank funds that have invested in Southcross Energy LLC (the “Charlesbank Fund”), that all compensation otherwise payable to Mr. Biotti as a result of being a director of our General Partner should be paid as follows: (i) cash compensation should be paid directly to Charlesbank and (ii) in lieu of equity compensation, any such additional compensation should be paid in cash directly to Charlesbank. On April 13, 2016, Mr. Biotti resigned from the board of directors of our General Partner. See Item 9B for additional information.
Mr. Downie informed us that in accordance with the internal policies of Tailwater and the terms of the limited partnership agreements for the Tailwater funds, all cash compensation otherwise payable to Mr. Downie as a result of being a director of our General Partner should be paid as follows: (i) cash compensation should be paid directly to Tailwater and (ii) in lieu of equity compensation, any such additional compensation should be paid in cash directly to Tailwater.
Mr. Henderson also informed us that in accordance with the internal policies of EIG and the terms of the limited partnership agreements for the EIG funds, that all compensation otherwise payable to Mr. Henderson as a result of being a director of our General Partner should be paid as follows: (i) cash compensation should be paid directly to EIG and (ii) in lieu of equity compensation, any such additional compensation should be paid directly to EIG.
Director Compensation for 2015
The following table presents the cash, equity awards and other compensation earned, paid or awarded to each of our directors during the year ended December 31, 2015:
Name
Fees earned or
paid in cash
 
Equity awards
 
 
Total
Jon M. Biotti (1)
$
75,400

 
$
75,000

 
(4)
$
150,400

Jason Downie (2)
$
66,500

 
$
75,000

 
(4)
$
141,500

Wallace C. Henderson (3)
$
66,500

 
$
75,000

 
(4)
$
141,500

Nicholas J. Caruso (5)
$
18,200

 
$
77,383

 
(6)
$
95,583

Jerry W. Pinkerton
$
94,900

 
$
76,988

 
(7)
$
171,888

Ronald G. Steinhart
$
74,900

 
$
76,988

 
(8)
$
151,888

Bruce A. Williamson
$
84,800

 
$
76,988

 
(9)
$
161,788

_______________________________________________________________________________
(1)
Director associated with Charlesbank. Cash compensation was paid in cash to Charlesbank.
(2)
Director associated with Tailwater. Cash compensation was paid to Tailwater.
(3)
Director associated with EIG. Cash compensation was paid to EIG.
(4)
In lieu of an equity grant pursuant to the LTIP, the director received a cash payment. Mr. Biotti and Mr. Henderson do not hold any equity as of December 31, 2015. As a result of the relationship of Mr. Downie to Southcross Holdings Borrower LP, Mr. Downie may be deemed to indirectly beneficially own the 6,616,400 common units, 15,958,990

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Class B Convertible Units and 12,213,713 subordinated units owned by Southcross Holdings Borrower LP. See Item 12 to this Annual Report.
(5)
On July 15, 2015, Mr. Caruso was appointed as a director of our General Partner. In connection with Mr. Caruso's appointment, the size of the Board of our General Partner was increased from seven directors to eight directors.
(6)
Mr. Caruso received 6,454 common units on July 15, 2015 based on a per unit price of $11.62, which was the average of the daily per unit closing price of our common units for the ten trading days immediately before July 15, 2015. The grant date fair value was $77,383 based on a per unit price of $11.99, which was the closing price on July 15, 2015. Including the common units granted to Mr. Caruso on July 15, 2015, Mr. Caruso has a total of 6,454 common units outstanding as of December 31, 2015. See Item 12 of this Annual Report.
(7)
Mr. Pinkerton received 5,365 common units on April 1, 2015 based on a per unit price of $13.98, which is the average of the daily per unit closing price of our common units for the ten trading days immediately before April 1, 2015. The grant date fair value was $76,988 based on a per unit price of $14.35, which was the closing price on April 1, 2015. Including the common units granted to Mr. Pinkerton on April 1, 2015, Mr. Pinkerton has a total of 14,739 common units outstanding as of December 31, 2015. See Item 12 of this Annual Report.
(8)
Mr. Steinhart received 5,365 common units on April 1, 2015 based on a per unit price of $13.98, which is the average of the daily per unit closing price of our common units for the ten trading days immediately before April 1, 2015. The grant date fair value was $76,988 based on a per unit price of $14.35, which was the closing price on April 1, 2015. Including the common units granted to Mr. Steinhart on April 1, 2015, Mr. Steinhart has a total of 26,879 common units outstanding as of December 31, 2015. See Item 12 of this Annual Report.
(9)
Mr. Williamson received 5,365 phantom units on April 1, 2015 based on a per unit price of $13.98, which is the average of the daily per unit closing price of our common units for the ten trading days immediately before April 1, 2015. Pursuant to Mr. Williamson’s election to defer such award in accordance with the Non-Employee Director Deferred Compensation Plan, Mr. Williamson was issued the reported phantom units. The grant date fair value was $76,988 based on a per unit price of $14.35, which was the closing price on April 1, 2015. Including the phantom units granted to Mr. Williamson on April 1, 2015, Mr. Williamson has a total of 31,994 phantom units outstanding as of December 31, 2015.

Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table sets forth certain information regarding the beneficial ownership of our units as of April 8, 2016 by:
each person known to us to beneficially own 5% or more of any class of our outstanding units (including any "group" as that term is used in Section 13(d)(3) of the Exchange Act;
each of the directors and named executive officers of our General Partner; and
all of the directors and executive officers of our General Partner as a group.
All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders, as the case may be, or based on a review of the copies of reports furnished to us.
Our General Partner is indirectly owned 100% by Holdings. EIG and Tailwater each indirectly own approximately one-third of Holdings, and a group of consolidated lenders under Holdings' revolving credit facility and term loan own the remaining one-third equity interest, which was previously owned by Charlesbank Capital Partners, LLC. The general partner of Holdings is Southcross Holdings GP LLC, of which EIG and Tailwater each indirectly own approximately one-third, and a group of consolidated lenders under Holdings' revolving credit facility and term loan own the remaining one-third equity interest, which was previously owned by Charlesbank Capital Partners, LLC. Our General Partner owns all of the general partner interests in us.
The amounts and percentage of units beneficially owned are reported on the basis of SEC regulations governing the determination of beneficial ownership of securities. Under the SEC regulations, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote, or to direct the voting, of such security, and/or “investment power,” which includes the power to dispose, or to direct the disposition of, such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, a right to acquire beneficial ownership of a security within 60 days of April 8, 2016 by a person, if any, are deemed to be outstanding for computing the percentage of outstanding securities of the class by such person, but are not deemed to be outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting power and

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sole investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.
The percentages of units beneficially owned are based on a total of 28,512,465 common units, 12,213,713 subordinated units and 15,958,990 Class B Convertible Units outstanding as of April 8, 2016.
Name and address of beneficial owner(1)
 
Common units
beneficially owned
 
Percentage of
common units
beneficially owned
 
Subordinated units
beneficially owned(1)
 
Percentage of
subordinated units
beneficially owned
 
Class B Convertible Units beneficially owned(1)
 
Percentage of
Class B Convertible Units
beneficially owned
 
Percentage of
total common,
subordinated and Class B Convertible Units
beneficially owned
Our Holding Company:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Southcross Holdings LP(2)(3)(4)
 
6,616,400

 
23.3
%
 
12,213,713

 
100.0
%
 
15,958,990

 
100
%
 
61.5
%
5% Owners Not Listed Above or Below:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Southcross Energy LLC(4)
 
6,616,400

 
23.3
%
 
12,213,713

 
100.0
%
 
15,958,990

 
100
%
 
61.5
%
EIG BBTS Holdings, LLC(5)
 
6,616,400

 
23.3
%
 
12,213,713

 
100.0
%
 
15,958,990

 
100
%
 
61.5
%
TW BBTS Aggregator LP(6)
 
6,616,400

 
23.3
%
 
12,213,713

 
100.0
%
 
15,958,990

 
100
%
 
61.5
%
Oppenheimer Funds, Inc.(7)
 
1,731,229

 
6.1
%
 

 

 

 

 
3.1
%
Current Directors and Named Executive Officers of Our General Partner:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
J. Michael Anderson(2)(8)
 
76,213

 
*

 

 

 

 

 
*

David W. Biegler(2)
 
60,596

 
*

 

 

 

 

 
*

Jon M. Biotti(4)(9)
 

 

 

 

 

 

 

John E. Bonn(2)
 
34,900

 
*

 

 

 

 

 
*

Nicholas J. Caruso(2)
 
6,454

 
*

 

 

 

 

 
*

Jason H. Downie(6)(10)
 
6,616,400

 
23.3
%
 
12,213,713

 
100.0
%
 
15,958,990

 
100
%
 
61.5
%
Wallace C. Henderson(11)
 

 

 

 

 

 

 

Jerry W. Pinkerton(2)
 
14,739

 
*

 

 

 

 

 
*

Ronald G. Steinhart(2)(12)
 
26,879

 
*

 

 

 

 

 
*

Bruce A. Williamson(2)(13)
 
12,739

 
*

 

 

 

 

 
*

All current directors and executive officers of our General Partner as a group (consisting of 10 persons)(4)(6)(11)(12)(13)(14)
 
6,772,707

 
23.8
%
 
12,213,713

 
100.0
%
 
15,958,990

 
100
%
 
61.7
%
_______________________________________________________________________________
*
An asterisk indicates that the person or entity owns less than one percent.
(1)
This beneficial ownership table was prepared as of the Ownership Reference Date. The subordinated units convert into common units on a one-for-one basis on the expiration of the Subordination Period (as defined in the Partnership Agreement). The Class B Convertible Units convert into common units at the Class B Conversion Rate (as defined in our Partnership Agreement) on the Class B Conversion Date (as defined in the Partnership Agreement). Because such subordinated units and Class B Convertible Units were acquired in connection with transactions having the purpose or effect of changing or influencing the control of us, such subordinated units and Class B Convertible Units are considered converted for purposes of the calculations of the amounts noted under Rule 13d-3(d)(1)(i) of the Exchange Act. Pursuant to Rule 13d-3(d)(1)(i), the subordinated units and Class B Convertible Units are deemed outstanding for computing the percentage of the class owned by such beneficial owner, but not deemed to be outstanding for the purpose of computing the percentage of the class for any other person. The beneficial ownership reported for the Class B Convertible Units includes additional Class B Convertible Units issued in kind as distributions, including Class B Convertible Units issued on November 13, 2015 in connection with a distribution to holders of record of Class B Convertible Units on November 9, 2015.
(2)
The address for this person or entity is 1717 Main Street, Suite 5200, Dallas, Texas 75201.
(3)
Holdings, through its wholly-owned subsidiaries, owns 100% of our General Partner, 6,616,400 of our common units, 12,213,713 of our subordinated units and 15,958,990 of our Class B Convertible Units.
(4)
Based on a Schedule 13D/A filed with the SEC on May 21, 2015. The filing was made jointly by Southcross Energy LLC, Charlesbank Capital Partners, LLC, Southcross Holdings GP LLC, Southcross Holdings LP, Southcross Holdings Guarantor GP LLC, Southcross Holdings Guarantor LP, Southcross Holdings Borrower GP LLC and Southcross Holdings Borrower LP. Each party to the Schedule 13D, as amended, shares voting and dispositive power. Jon Biotti, a former director of our General Partner, is a managing director of Charlesbank Capital Partners, LLC, the investment adviser to the Charlesbank funds. Mr. Biotti disclaims beneficial interest in our common units, subordinated units and Class B Convertible Units, except to the extent of his pecuniary interest therein. The address for each party to the Schedule 13D, as amended, except for Charlesbank Capital Partners, LLC, is 1717 Main Street, Suite 5200, Dallas, Texas 75201. The address for Charlesbank Capital Partners, LLC is 200 Clarendon Street, 54th Floor, Boston, Massachusetts 02116. Effective April 13, 2016, Mr. Biotti resigned as a member of the board of directors of our General Partner and Southcross Energy LLC no longer holds an equity interest in Holdings.
(5)
Based on a Schedule 13D/A filed with the SEC on May 15, 2015. The filing was made jointly by EIG BBTS Holdings, LLC, EIG Management Company, LLC, EIG Asset Management, LLC, EIG Global Energy Partners, LLC, The R. Blair Thomas 2010 Irrevocable Trust, and R. Blair Thomas. Each party to the Schedule 13D, as amended, shares voting and dispositive power. The address for each party to the Schedule 13D, as amended, is 1700 Pennsylvania Ave. NW, Suite 800, Washington, D.C. 20006.
(6)
Based on a Schedule 13D/A filed with the SEC on May 15, 2015. The filing was made jointly by TW BBTS Aggregator LP, BB-II Holdco LP, TW/LM GP Sub, LLC, Tailwater Energy Fund I LP, TW GP EF-I, LP, TW GP EF-I GP, LLC, TW GP Holdings, LLC, Tailwater Holdings, LP, Tailwater Capital LLC, Jason Downie and Edward Herring. Each party to the Schedule 13D, as amended, shares voting and dispositive power. Based on the

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relationship of Jason H. Downie to Southcross Holdings Borrower LP, Downie, a director of our General Partner, may be deemed to indirectly beneficially own the common units, subordinated units and Class B Convertible Units held by Southcross Holdings Borrower LP. The address for each party to the Schedule 13D, as amended, is 300 Crescent Court, Suite 200, Dallas, Texas 75201.
(7)
Based on a Schedule 13G/A filed with the SEC on February 5, 2016. The filing was made jointly by OppenheimerFunds, Inc. (“OF”) and Oppenheimer SteelPath MLP Income Fund (“OSP”). The filing reflects that OF has shared voting power and shared dispositive power over 1,731,229 common units and beneficial ownership of 1,731,229 common units. The filing also reflects that OSP has sole voting power and shared dispositive power over 1,713,278 common units and beneficial ownership of 1,713,278. OF disclaims beneficial ownership of the 1,731,229 common units, which includes the ownership of OSP. OSP also disclaims beneficial ownership of the 1,713,278 common units. The address for OF is Two World Financial Center, 225 Liberty Street, New York, New York 10281 and the address for OSP is 6803 S. Tucson Way, Centennial, Colorado 80112.
(8)
As of June 26, 2015, Mr. Anderson is no longer an officer of our General Partner. See our Current Reports on Form 8-K filed with the SEC on June 8, 2015 and July 8, 2015. The beneficial ownership for Mr. Anderson is reported as known to us effective as of June 26, 2015.
(9)
The address for Mr. Biotti is 200 Clarendon Street, 54th Floor, Boston, Massachusetts 02116.
(10)
Mr. Downie owns no units directly. Includes 6,616,400 common units, 12,213,713 subordinated units and 15,958,990 Class B Convertible Units indirectly owned by Holdings. Based on the relationship of Jason H. Downie to Southcross Holdings Borrower LP, Mr. Downie may be deemed to indirectly beneficially own the common units, subordinated units and Class B Convertible Units held by Southcross Holdings Borrower LP. Mr. Downie disclaims beneficial ownership of the securities reported, except to the extent of Mr. Downie’s indirect pecuniary interest.
(11)
The address for Mr. Henderson is 1700 Pennsylvania Ave. NW, Suite 800, Washington, D.C. 20006.
(12)
Includes 16,879 common units owned directly by Mr. Steinhart. Also includes 2,500 common units owned by each of two of Mr. Steinhart’s sons and 1,000 common units owned by each of five trusts established for the benefit of Mr. Steinhart’s grandchildren, over which Mr. Steinhart shares voting and dispositive power. Mr. Steinhart has no pecuniary interest in, and disclaims any ownership of, such common units that are not owned by Mr. Steinhart directly.
(13)
Represents phantom units issued under the Non-Employee Director Deferred Compensation whereby Mr. Williamson has the right to acquire common units within 30 days of termination of his services. Mr. Williamson has elected to defer all earned compensation under the Non-Employee Director Deferred Compensation Plan until he is no longer a director of our General Partner. In accordance with the Non-Employee Director Deferred Compensation Plan, Mr. Williamson has a total of 29,543 phantom units, 16,804 of which will be settled in cash equal to the fair market value of our common units on the date of termination of Mr. Williamson’s services (and which are not included in the table).
(14)
Does not include any unvested phantom units granted to such directors and executive officers under the LTIP.
Securities Authorized for Issuance Under Equity Compensation Plan(1)
We have one compensation plan under which our common units are authorized for issuance, the LTIP. This equity compensation plan was approved by our unitholders. The following table sets forth certain information relating to the LTIP as of December 31, 2015:
 
(a)
 
(b)
 
(c)
Plan category
Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights
 
Weighted-average
exercise price of
outstanding options,
warrants and rights
 
Number of securities remaining
available for future issuance under
equity compensation plans
(excluding securities reflected
in column(a))
Equity compensation plans approved by securities holders
470,750

 

 
5,400,284

Equity compensation plans not approved by security holders

 

 

Total
470,750

 
$

 
5,400,284

_______________________________________________________________________________
(1)
See Note 13 to our consolidated financial statements for more information. No value is shown in column (b) of the table because the phantom units do not have an exercise price.

Item 13.
Certain Relationships and Related Transactions, and Director Independence
As of April 8, 2016, Holdings owns 6,616,400 common units, 12,213,713 subordinated units and 15,958,990 Class B Convertible Units, representing a combined 61.4% limited partner interest in us. In addition, Holdings owns and controls our General Partner, which owns a 2.0% General Partner interest in us and all of our incentive distribution rights.
The following table summarizes the distributions and payments owed by us to our General Partner and its affiliates in connection with our ongoing operations and liquidation. Certain of these distributions and payments were determined among affiliated entities and, consequently, are not the result of arm's-length negotiations.

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Operational Stage
 
Distributions to our General Partner and its affiliates
We generally make cash distributions (except with respect to our Class B Convertible Units, which are paid in Class B PIK Units) of 98.0% to our unitholders pro rata (including to Holdings, as the holder of a 61.5% limited partnership interest in us) and 2.0% to our General Partner, assuming our General Partner makes any capital contributions necessary to maintain its 2.0% general partner interest in us. In addition, if distributions exceed the minimum quarterly distribution and target distribution levels, our General Partner is entitled to increasing percentages of the distributions, up to 48.0% of the distributions above the highest target distribution level in connection with its incentive distribution rights.
Payments to our General Partner and its affiliates
Our General Partner does not receive a management fee or other compensation for its management of us. However, our General Partner and its affiliates are entitled to reimbursement for all expenses incurred on our behalf, including, among other items, compensation expense for all employees required to manage and operate our business. Our Partnership Agreement provides that our General Partner will determine the amount of these reimbursed expenses. In addition, as described below, these employees provide services to affiliated entities, including Holdings, and the expenses for these services are allocated by the board of directors of our General Partner.
Withdrawal or removal of our General Partner
If our General Partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case, for an amount equal to the fair market value of those interests.
Liquidation Stage
 
Liquidation
Upon our liquidation, our partners, including our General Partner, will be entitled to receive liquidating distributions according to their particular capital account balances.
Southcross Energy Partners GP, LLC (our General Partner)
Our General Partner does not receive a management fee or other compensation for its management of us.  However, our General Partner and its affiliates are entitled to reimbursements for all expenses incurred on our behalf, including, among other items, compensation expense for all employees required to manage and operate our business.  During the year ended December 31, 2015, we incurred expenses related to these reimbursements, which are reflected in operating expenses in our consolidated statements of operations.
Holdings Chapter 11 Reorganization

On March 28, 2016, Holdings and certain of its subsidiaries (other than us, our General Partner and our subsidiaries) filed a pre-packaged plan of reorganization (the “POR”) under Chapter 11 of the U.S. Bankruptcy Code in the Southern District of Texas to restructure its debt obligations and strengthen its balance sheet. Our operations, customers, suppliers, partners and other constituents were excluded from such proceeding. On April 11, 2016, the bankruptcy court confirmed Holdings’ POR, and on April 13, 2016, Holdings and its subsidiaries emerged from its bankruptcy and consummated the following principal transactions:

issued 33.34% of the limited partner interests of Holdings to the lenders under Holdings’ credit facility in exchange for the elimination of certain funded debt obligations;

issued 33.33% of the limited partner interests of Holdings to EIG in exchange for approximately $85 million in cash;

issued 33.33% of the limited partner interests of Holdings to Tailwater in exchange for approximately $85 million in cash;

committed to provide us $50 million (as part of the Equity Cure Agreement discussed below), from the $170 million in new equity contributed to Holdings from the Sponsors, to ensure we have sufficient liquidity to comply with the applicable financial covenants set forth in our credit agreement; and

paid all of the receivable due to us.

In addition, pursuant to the terms of the POR, the Lenders have the right to appoint two members (one of which must be independent) to the board of directors of our general partner due to their equity interest in Holdings. The directors appointed by the Lenders will replace the directors previously appointed by Charlesbank Capital Partners, LLC. The court authorized

141


Holdings to continue to pay all of its trade creditors, suppliers and contractors, including us, in the ordinary course of business and any amounts owed by Holdings to these parties will not be impacted by the bankruptcy proceeding. We believe Holdings’ reorganization and POR will enhance our liquidity position, strengthen our balance sheet and position it to continue to support our business and growth.
Acquisition of TexStar Rich Gas System
On August 4, 2014, we completed our approximately $450.0 million acquisition of the TexStar Rich Gas System in connection with consummation of the Holdings Transaction.
In exchange for the TexStar Rich Gas System (the "Contribution"), we paid $80 million in cash to TexStar, assumed $100 million of debt (which was immediately repaid by the Partnership’s new term loan facility, as described below) and issued 14,633,000 Class B Convertible Units to TexStar.
Due to the interest of Southcross Energy LLC (which, at the time of the Contribution, owned a significant stake in our outstanding units and 100% of our General Partner) in the Contribution, the conflicts committee of the board of directors of our General Partner reviewed the terms of the definitive agreement for the Contribution and approved our entry into it. The conflicts committee, composed of two of our independent directors, retained separate counsel and an independent financial advisor, which rendered a fairness opinion.
Consummation of Holdings Transaction
Contemporaneously with the consummation of the Contribution, Southcross Energy LLC, which previously owned a significant stake in our outstanding units and 100% of our General Partner, completed its combination with TexStar.
As a result of the Holdings Transaction, Holdings, through its wholly-owned subsidiary Southcross Holdings Borrower LP, acquired from (a) BBTS Borrower LP ("BBTS") 100% of TexStar and its general partner and (b) from Southcross Energy LLC 2,116,400 of our common units and 12,213,713 of our subordinated units, collectively representing an approximate 39.8% limited partner interest in us, as well as 100% of our General Partner, which owns an approximate 2% general partner interest in us and our incentive distribution rights. In November 2014, BBTS, an entity controlled by EIG and Tailwater, distributed its interest in Holdings to EIG and Tailwater in roughly equal proportions. Southcross Energy LLC is controlled by Charlesbank. As a result of the Holdings Transaction, and the subsequent distribution by BBTS of its interests to EIG and Tailwater, each of Charlesbank, EIG and Tailwater owned approximately one-third of Holdings.
Waiver of Distribution on Subordinated Units
Beginning with the third quarter of 2014, until such time that we have a Distributable Cash Flow Ratio of at least 1.0, Holdings, the indirect holder of all of our subordinated units, has waived the right to receive distributions on any subordinated units that would cause our Distributable Cash Flow Ratio to be less than 1.0. In addition, the Credit Agreement Amendment (defined in Note 8 to the consolidated financial statements) imposed additional restrictions on our ability to declare and pay quarterly cash distributions with respect to our subordinated units.
Holdings Drop-Down Acquisition

On May 7, 2015, we acquired gathering, treating, compression and transportation assets (the “2015 Holdings Acquisition”) pursuant to a Purchase, Sale and Contribution Agreement among Holdings, TexStar Midstream Utility, LP, Frio LaSalle Pipeline, LP, us and certain of our subsidiaries. The acquired assets consist of the Valley Wells sour gas gathering and treating system (the "Valley Wells System"), compression assets that are part of the Valley Wells and Lancaster gathering and treating systems (the "Compression Assets") and two NGL pipelines. Due to the common control aspects in the 2015 Holdings Acquisition, the Partnership’s financial results retrospectively include the financial results for the Valley Wells System and the Compression Assets for all periods ending after August 4, 2014, the date of the Holdings Transaction. For additional details regarding the 2015 Holdings Acquisition, see Notes 1 and 3 to our consolidated financial statements.
Recent Lack of Quarterly Distributions
In January 2016 and effective for the fourth quarter of 2015, the board of directors of our General Partner voted not to pay a quarterly distribution and instead to reserve any excess cash for the operation of our business. Quarterly distributions were paid by the Partnership through the third quarter of 2015. The board of directors of our General Partner and our management believe this suspension to be in the best interest of our unitholders. The board of directors and management will continue to evaluate the Partnership's ability to reinstate the distribution in future periods.

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Board of Directors
The board of directors of our General Partner is comprised of eight directors. Pursuant to the organizational documents of the general partner of Holdings, two directors (one of whom must be independent) on our board of directors will be appointed by each of EIG, Tailwater and the group of lenders who received membership interest in Holdings in connection with Holdings’ Chapter 11 reorganization. On July 15, 2015, a fourth outside director was elected to serve on the board of directors of our General Partner. The eighth member of the board of directors of our General Partner, and its chairman, is David W. Biegler. Mr. Biegler will serve as chairman until the earlier of August 4, 2016 and his death or resignation.
All of our directors are compensated equally for similar responsibilities and reimbursed for expenses incurred for their services to us. For the years ended December 31, 2015 and 2014, we paid Charlesbank, EIG and Tailwater $0.3 million and $0.4 million, respectively, for director fees and related expenses. These expenses are reflected in general and administrative expenses in our consolidated statements of operations.
Series A Conversion
The Holdings Transaction constituted a change of control pursuant to our Second Amended and Restated Agreement of Limited Partnership relating to our series A preferred units, giving the holders the right to convert their series A preferred units into common units based on a 110% exchange ratio. The closing price of the common units on the date of closing of the Holdings Transaction was $22.17. All of the holders of our series A preferred units, including Southcross Energy LLC, which previously owned a significant stake in our outstanding units and 100% of our General Partner, elected to convert all of their series A preferred units into common units in connection with the closing of the Holdings Transaction.
Shared Services with Southcross Holdings LP and Other Affiliates
Certain of the employees of our General Partner perform management, administrative, operational and workforce related services to affiliated entities, including Holdings, which owns 100% of our General Partner, and an affiliate that is jointly owned by EIG and Tailwater, two of our Sponsors. The expenses associated with these services, which are shared with these entities, are recorded in general and administrative expense in our statement of operations and are allocated in a manner approved by the board of directors and Conflicts Committee. For the years ended December 31, 2015 and 2014, we allocated $3.4 million and $1.0 million, respectively, to Holdings. For the year ended December 31, 2014, we allocated $0.1 million to an affiliate of two of our Sponsors.
The Conflicts Committee of the board of directors of our General Partner has reviewed the cost allocation methodology applicable to these services and, based on representations from management, determined that the fees charged were fair.
Other Transactions with Affiliates

In conjunction with the TexStar Rich Gas System Transaction, we entered into a gas gathering and processing agreement (the “G&P Agreement”) and an NGL sales agreement (the “NGL Agreement”) with an affiliate of Holdings. Under the terms of these commercial agreements, we transport, process and sell rich natural gas for the affiliate of Holdings in return for agreed-upon fixed fees, and we can sell natural gas liquids that we own to Holdings at agreed-upon fixed prices. The NGL Agreement also permits us to utilize Holdings’ fractionation services at market-based rates.

In conjunction with the 2015 Holdings Acquisition, we entered into a series of commercial agreements with affiliates of Holdings including a gas gathering and treating agreement, a compression services agreement, a repair and maintenance agreement and an NGL transportation agreement. Under the terms of these commercial agreements, we gather, treat, transport, compress and redeliver natural gas for the affiliates of Holdings in return for agreed-upon fixed fees. In addition, under the NGL transportation agreement, we transport a minimum volume of NGLs per day at a fixed rate per gallon. The operational expense associated with such agreements has been capped at $1.7 million per quarter. During the year ended December 31, 2015, we exceeded this cap by $2.7 million which was recorded as a receivable from Holdings on our consolidated balance sheets.

During the year ended December 31, 2015 and 2014, the Partnership recorded revenues from affiliates of $94.7 million and $13.3 million in accordance with the G&P Agreement, the NGL Agreement and the commercial agreements entered into in connection with the 2015 Holdings Acquisition.
 
We had accounts receivable due from affiliates of $49.7 million and $11.3 million as of December 31, 2015 and 2014, respectively, and accounts payable due to affiliates of $7.9 million and $12.9 million as of December 31, 2015 and 2014, respectively. The affiliate receivable and payable balances are related primarily to transactions associated with Holdings, noted above, and our joint venture investments (defined in Note 15 to our consolidated financial statements).


143


During the year ended December 31, 2015, Holdings purchased $2.3 million of office leasehold improvements from SXE.

In 2014, we paid approximately $2.8 million to Black Creek Well Services, LP, an entity in which two of our Sponsors (EIG and Tailwater) have an indirect controlling interest, for servicing work it performed for us.
Procedures for Review, Approval and Ratification of Related-Person Transactions
We have a Code of Business Conduct and Ethics that requires the board of directors of our General Partner or its Conflicts Committee to review periodically all related-person transactions that are required to be disclosed under SEC rules and, when appropriate, to authorize or ratify all such transactions. If the board of directors of our General Partner or its Conflicts Committee considers ratification of a related-person transaction and determines not to so ratify, the Code of Business Conduct and Ethics provides that our management will make all reasonable efforts to cancel or annul the transaction.
Our Code of Business Conduct and Ethics provides that, in determining whether to recommend the initial approval or ratification of a related-person transaction, the board of directors of our General Partner or its Conflicts Committee should consider all of the relevant facts and circumstances available, including (if applicable), but not limited to: (i) whether there is an appropriate business justification for the transaction, (ii) the benefits that accrue to us as a result of the transaction, (iii) the terms available to unrelated third parties entering into similar transactions, (iv) the impact of the transaction on director independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediately family member of a director is a partner, shareholder, member or executive officer), (v) the availability of other sources for comparable products or services, (vi) whether it is a single transaction or a series of ongoing, related transactions, and (vii) whether entering into the transaction would be consistent with our Code of Business Conduct and Ethics.
See Part II, Item 10 of this report for a discussion regarding director independence.

Item 14.
Principal Accountant Fees and Services
We have engaged Deloitte & Touche LLP as our independent registered public accounting firm. The following table summarizes fees we have paid Deloitte & Touche LLP for the audit of our annual financial statements and other services rendered for the years ended December 31, 2015 and 2014:
 
Year ended
December 31,
 
2015
 
2014
Audit fees(1)
$
1,357,900

 
$
1,620,455

Audit-related fees(2)
300,000

 
523,236

Tax fees(3)
48,882

 
71,494

All other fees(4)

 
96,422

 
$
1,706,782

 
$
2,311,607

____________________________________________________________________________
(1) The Audit fees are fees billed for professional services for the audit and quarterly reviews of the Partnership’s consolidated financial statements, review of other SEC filings, including registration statements, and issuance of comfort letters and consents.
(2) Audit-related fees are fees billed for assurance and related services related to consultations and audits performed in connection with acquisitions, due diligence services related to the TexStar combination transaction and assistance with the implementation of Section 404 of the Sarbanes-Oxley Act.
(3) Tax fees are billed for sales tax planning and advisory services.
(4) All other fees are fees billed in connection with certain integration services from the TexStar combination transaction.
Audit Committee Approval of Audit and Non-Audit Services
The Audit Committee of the board of directors of our General Partner has adopted a policy with respect to services which may be performed by Deloitte & Touche LLP. This policy lists specific audit-related and tax services as well as any other services that Deloitte & Touche LLP is authorized to perform and sets out specific dollar limits for each specific service, which may not be exceeded without additional Audit Committee authorization. The Audit Committee receives quarterly reports on the status of expenditures pursuant to that policy. The Audit Committee reviews the policy at least annually in order to approve

144


services and limits for the current year. Any service that is not clearly enumerated in the policy must receive specific pre-approval by the Audit Committee or by its chairman, to whom such authority has been conditionally delegated, prior to engagement.
The Audit Committee has approved the appointment of Deloitte & Touche LLP as independent registered public accounting firm to conduct the audit of our financial statements for the year ended December 31, 2015.

145



Item 15.
Exhibits and Financial Schedules
(a)    Financial Statements
(1)    Included in Part II, Item 8 of this report.
 
 
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2015 and 2014
Consolidated Statements of Operations for the Years Ended December 31, 2015, 2014, and 2013
Consolidated Statements of Comprehensive Loss for the Years Ended December 31, 2015, 2014, and 2013
Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014, and 2013
Consolidated Statements of Changes in Partners' Capital for the Years Ended December 31, 2015, 2014 and 2013
Notes to Consolidated Financial Statements
(2)    All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.
(3)    Exhibit Index.
An "Exhibit Index" has been filed as part of this report beginning in sub-item (b) below of this item and is incorporated herein by reference.
Schedules other than those listed above are omitted because they are not required, not material, not applicable or the required information is shown in the financial statements or notes thereto.
Agreements attached or incorporated herein as exhibits to this report are included to provide investors with information regarding the terms and conditions of such agreements and are not intended to provide any other factual or disclosure information about the Partnership or the other parties to the agreements.
Such agreements may contain representations and warranties by the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and (i) should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate, (ii) have been qualified by disclosures that were made to the other party or parties in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement, (iii) may apply standards of materiality in a way that is different from what may be viewed as material to you or other investors and (iv) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments. Accordingly, the representations and warranties in such agreements may not describe the actual state of affairs as of the date they were made or at any other time.
(b)    Exhibits and Exhibit Index
Exhibit
Number
 
Description
3.1
 
Certificate of Limited Partnership of Southcross Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).
3.2
 
Third Amended and Restated Agreement of Limited Partnership of Southcross Energy Partners, L.P., dated as of August 4, 2014 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K dated August 4, 2014).
3.3
 
Certificate of Formation of Southcross Energy Partners GP, LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).
3.4
 
Second Amended and Restated Limited Liability Company Agreement of Southcross Energy Partners GP, LLC, dated as of August 4, 2014 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K dated August 4, 2014).

146


Exhibit
Number
 
Description
4.1
 
Registration Rights Agreement, dated as of April 12, 2013, by and between Southcross Energy Partners, L.P. and Southcross Energy LLC (incorporated by reference to Exhibit 4.1 to the Annual Report on Form 10-K for the year ended December 31, 2012).
10.1
 
Third Amended and Restated Revolving Credit Agreement, dated as of August 4, 2014, by and among Southcross Energy Partners, L.P., Wells Fargo Bank, N.A., as Administrative Agent, UBS Securities LLC and Barclays Bank PLC, as Co-Syndication Agents, JPMorgan Chase Bank, N.A., as Documentation Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated August 4, 2014).
10.2
 
Term Loan Credit Agreement, dated as of August 4, 2014, by and among Southcross Energy Partners, L.P., Wilmington Trust, National Association (successor to Wells Fargo Bank, N.A.), as Administrative Agent, UBS Securities LLC and Barclays Bank PLC, as Co-Syndication Agents, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K dated August 4, 2014).
10.3#
 
Southcross Energy Partners, L.P. Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated December 6, 2015).
10.4#
 
Form of Phantom Unit Award Agreement (incorporated by reference to Exhibit 10.5 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).
10.5#
 
Southcross Energy Partners GP, LLC and Southcross GP Management Holdings, LLC 2014 Equity Incentive Plan and Form of Unit Award Agreement (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K dated August 4, 2014).
10.6#
 
Severance Agreement, dated as of August 6, 2009, by and between Southcross Energy LLC and David W. Biegler (incorporated by reference to Exhibit 10.6 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).
10.7#
 
Southcross Energy Partners GP, LLC Non-Employee Director Compensation Arrangement (incorporated by reference to Exhibit 10.12 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2012).
10.8#
 
Southcross Energy Partners, L.P. Non-Employee Director Deferred Compensation Plan (incorporated by reference to Exhibit 10.13 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2012).
10.9
 
Contribution Agreement, dated as of June 11, 2014, by and among TexStar Midstream Services, LP, Southcross Energy Partners, L.P. and Southcross Energy GP LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated June 11, 2014).
10.10#*
 
Employment Agreement, dated as of March 5, 2015, by and between Southcross Energy Partners GP, LLC and John E. Bonn.
10.11#
 
Retention Agreement, dated as of November 6, 2014, by and between Southcross Energy Partners GP, LLC and J. Michael Anderson (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2014).
10.12
 
Purchase, Sale and Contribution Agreement, by and among Southcross Energy Partners, L.P., Southcross CCNG Gathering Ltd., Southcross NGL Pipeline Ltd., FL Rich Gas Services, LP, TexStar Midstream Utility, LP, Frio LaSalle Pipeline, LP and Southcross Holdings LP, dated as of May 7, 2015 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated May 7, 2015).
10.13
 
First Amendment to Third Amended and Restated Revolving Credit Agreement, by and among the Partnership, as borrower, Wells Fargo Bank, N.A., as Administrative Agent, and the lenders and other parties thereto, dated as of May 7, 2015 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K dated May 7, 2015).
10.14#
 
Severance Agreement, dated as of June 8, 2015, by and between Southcross Energy Partners GP, LLC and Bret M. Allan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated June 8, 2015).
10.15#
 
Severance Agreement, dated as of June 15, 2015, by and between Southcross Energy Partners GP, LLC and Joel D. Moxley (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated June 15, 2015).
10.16#
 
General Release Agreement, executed July 3, 2015 and effective June 26, 2015, by and between Southcross Energy Partners GP, LLC and J. Michael Anderson (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated July 3, 2015).
10.17
 
Equity Cure Contribution Agreement, dated March 17, 2016, by and between Southcross Energy Partners, L.P. and Southcross Holdings LP (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated March 22, 2016).
10.18*#
 
Southcross Energy Partners, L.P. 2016 Cash-Based Long-Term Incentive Plan and Form of Award Agreement.
10.19#
 
Retention Agreement, dated March 17, 2016, by and between Southcross Energy GP, LLC and Mr. John E. Bonn (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K dated March 22, 2016).

147


Exhibit
Number
 
Description
10.20#
 
Retention Agreement, dated March 17, 2016, by and between Southcross Energy GP, LLC and Mr. Bret M. Allan (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K dated March 22, 2016).
10.21#
 
Retention Agreement, dated March 17, 2016, by and between Southcross Energy GP, LLC and Mr. Joel D. Moxley (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K dated March 22, 2016).
10.22
 
Form of Senior Unsecured PIK Note, dated as of January 7, 2016, by and between Southcross Energy Partners, L.P. and the Lender party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated January 8, 2016).
21.1*
 
List of Subsidiaries of Southcross Energy Partners, L.P.
23.1*
 
Consent of Deloitte & Touche LLP.
31.1*
 
Certification of Chief Executive Officer required by Rule 13a-14(a)/15d-14(a).
31.2*
 
Certification of Chief Financial Officer required by Rule 13a-14(a)/15d-14(a).
32.1*
 
Certifications of Chief Executive Officer and Chief Financial Officer required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
101.INS*
 
XBRL Instance Document
101.SCH*
 
XBRL Taxonomy Extension Schema
101.CAL*
 
XBRL Taxonomy Extension Calculation Linkbase
101.DEF*
 
XBRL Taxonomy Extension Definition Linkbase
101.LAB*
 
XBRL Taxonomy Extension Label Linkbase
101.PRE*
 
XBRL Extension Presentation Linkbase
#
Management contracts or compensatory plans or arrangement.
*
Filed or furnished herewith.
The financial information contained in the XBRL (eXtensible Business Reporting Language)-related documents is unaudited.
(c)   Financial Statement Schedules
Not applicable.


148


SIGNATURES
Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
Southcross Energy Partners, L.P.
 
 
By: Southcross Energy Partners GP, LLC, our General Partner
Date:
April 14, 2016
By:
/s/ JOHN E. BONN
 
 
 
John E. Bonn
President and Chief Executive Officer
 
 
 
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the following persons on behalf of the registrant and in the capacities and on the dates indicated have signed this report below.
SIGNATURE
 
TITLE
 
DATE
 
 
 
 
 
/s/ JOHN E. BONN
 
President and Chief Executive Officer
 
April 14, 2016
John E. Bonn
 
(Principal Executive Officer)
 
 
 
 
 
 
 
/s/ BRET M. ALLAN
 
Senior Vice President and Chief Financial Officer
 
April 14, 2016
Bret M. Allan
 
(Principal Financial Officer)
 
 
 
 
 
 
 
/s/ G. TRACY OWENS
 
Vice President and Chief Accounting Officer
 
April 14, 2016
G. Tracy Owens
 
(Principal Accounting Officer)
 
 
 
 
 
 
 
/s/ DAVID W. BIEGLER
 
Chairman of the Board
 
 
April 14, 2016
David W. Biegler
 
 
 
 
 
 
 
 
/s/ JASON DOWNIE
 
Director
 
April 14, 2016
Jason Downie
 
 
 
 
 
 
 
 
/s/ WALLACE HENDERSON
 
Director
 
April 14, 2016
Wallace Henderson
 
 
 
 
 
 
 
 
/s/ JERRY W. PINKERTON
 
Director
 
April 14, 2016
Jerry W. Pinkerton
 
 
 
 
 
 
 
 
/s/ RONALD G. STEINHART
 
Director
 
April 14, 2016
Ronald G. Steinhart
 
 
 
 
 
 
 
 
/s/ BRUCE A. WILLIAMSON
 
Director
 
April 14, 2016
Bruce A. Williamson
 
 
 
 
 
 
 
 
/s/ NICHOLAS J. CARUSO
 
Director
 
April 14, 2016
Nicholas J. Caruso
 
 
 


149