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EX-31.2 - EXHIBIT 31.2 - Southcross Energy Partners, L.P.sxe-12312015xex312.htm
EX-23.1 - EXHIBIT 23.1 - Southcross Energy Partners, L.P.sxe-12312015xex231.htm
EX-10.18 - EXHIBIT 10.18 - Southcross Energy Partners, L.P.sxe-12312015xex1018.htm
EX-10.10 - EXHIBIT 10.10 - Southcross Energy Partners, L.P.sec-1231x2015xex1010.htm
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EX-31.1 - EXHIBIT 31.1 - Southcross Energy Partners, L.P.sxe-12312015xex311.htm
EX-21.1 - EXHIBIT 21.1 - Southcross Energy Partners, L.P.sxe-12312015xex211.htm
EX-32.1 - EXHIBIT 32.1 - Southcross Energy Partners, L.P.sxe-12312015xex321.htm
 
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.


5



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

6


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

7


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

10


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.

44


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).

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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.


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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.

64


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.