Southcross Energy Partners, L.P. - FORM 10-K

Southcross Energy Partners, L.P. - FORM 10-K - March 1, 2018

Attached files

Attached files

Southcross Energy Partners, L.P. Reports

file	filename
EX-32.1 - EXHIBIT 32.1 - Southcross Energy Partners, L.P.	sxe-12312017xex321.htm
EX-31.2 - EXHIBIT 31.2 - Southcross Energy Partners, L.P.	sxe-12312017xex312.htm
EX-31.1 - EXHIBIT 31.1 - Southcross Energy Partners, L.P.	sxe-12312017xex311.htm
EX-23.1 - EXHIBIT 23.1 - Southcross Energy Partners, L.P.	sxe-12312017xex231.htm
EX-21.1 - EXHIBIT 21.1 - Southcross Energy Partners, L.P.	sxe-12312017xex211.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, 2017



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 Representing 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. x

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," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer o	Accelerated filer o	Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company x	Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to section 13(a) of the Exchange Act. o

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

The aggregate market value of common units held by non-affiliates of the registrant on June 30, 2017 was approximately $69,887,015 based on the closing sale price and the number of outstanding common units held by non-affiliates on such date as reported on the New York Stock Exchange.

As of February 23, 2018, the registrant has 48,623,615 common units, 12,213,713 subordinated units and 18,656,071 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

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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, 2017



PART I
Item 1.	Business	6
Item 1A.	Risk Factors	22
Item 1B.	Unresolved Staff Comments	49
Item 2.	Properties	49
Item 3.	Legal Proceedings	50
Item 4.	Mine Safety Disclosures	50
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities	51
Item 6.	Selected Financial Data	53
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	53
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	67
Item 8.	Financial Statements and Supplementary Data	68
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	99
Item 9A.	Controls and Procedures	99
Item 9B.	Other Information	99
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	102
Item 11.	Executive Compensation	105
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	117
Item 13.	Certain Relationships and Related Transactions, and Director Independence	116
Item 14.	Principal Accountant Fees and Services	119
PART IV
Item 15.	Exhibits and Financial Statement Schedules	120
Item 16.	Form 10-K Summary	123
	Signatures	124

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FORWARD-LOOKING INFORMATION

Investors are cautioned that certain statements contained in this Annual Report on Form 10-K ("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;


•	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;


•	satisfaction of the conditions to the completion of the proposed Merger (defined in Note 1 to our consolidated financial statements), including receipt of the approval of our unitholders and the closing of the Contribution (defined in Note 1 to our consolidated financial statements);


•	the timing and likelihood of completion of the proposed Merger, including the timing, receipt and terms and

conditions of any required governmental and regulatory approvals for the proposed Merger that could reduce

anticipated benefits or cause the parties to abandon the proposed transaction;


•	the possibility that the expected synergies and value creation from the proposed Merger will not be realized or will not

be realized within the expected time period;


•	disruption from the proposed Merger making it more difficult to maintain business and operational relationships;


•	the risk that unexpected costs will be incurred in connection with the proposed Merger;


•	the possibility that the proposed Merger does not close, including due to the failure to satisfy the closing conditions;

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•	the impact on our financial condition and operations resulting from the financial condition and operations of our controlling unitholder, Southcross Holdings LP and its ability to pay amounts to us;


•	changes in general economic conditions; and


•	other financial, operational and legal risks and uncertainties detailed from time to time in our filings with the U.S. Securities and Exchange Commission.

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

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

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PART I


Item 1.	Business

The following discussion of our business provides information regarding our principal gathering, transportation, processing, NGL fractionation and other assets. For a discussion of our results of operations, please read Part II, Item 7 of this report.

General Overview

Southcross Energy Partners, L.P. (the "Partnership," "Southcross," "we," "our" or "us") is a Delaware limited partnership formed in April 2012. Our common units are listed on the New York Stock Exchange under the symbol "SXE." We are a master limited partnership, headquartered in Dallas, Texas, that provides natural gas gathering, processing, treating, compression and transportation services and access to 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 two gas processing plants, one fractionation facility and gathering and transportation pipelines.

On August 4, 2014, Southcross Energy LLC, a Delaware limited liability company and the predecessor of the Partnership, and TexStar Midstream Services, LP, a Texas limited partnership combined pursuant to a Contribution Agreement in which Southcross Holdings LP, a Delaware limited partnership (“Holdings”) was formed (the "Holdings Transaction"). As a result of the Holdings Transaction, Holdings indirectly owns 100% of Southcross Energy Partners GP, LLC, a Delaware limited liability company, our general partner (“General Partner”) (and therefore controls us), all of our subordinated and Class B convertible units (the "Class B Convertible Units") and currently owns 54.5% of our common units. Our General Partner owns an approximate 2.0% interest in us and all of our incentive distribution rights.

Following the emergence of Holdings from its Chapter 11 reorganization proceeding on April 13, 2016 (as discussed below), EIG Global Energy Partners, LLC (“EIG”) and Tailwater Capital LLC (“Tailwater”) (collectively, the “Sponsors”) each indirectly own approximately one-third of Holdings, and a group of consolidated lenders (or their assignees) under Holdings' term loan (the "Lenders") own the remaining one-third of Holdings.

Recent Developments

The AMID Transactions

Contribution Agreement. On October 31, 2017, we and our General Partner entered into an Agreement and Plan of Merger (“Merger Agreement”) with American Midstream Partners, L.P. (“AMID”), American Midstream GP, LLC, the general partner of AMID (“AMID GP”), and a wholly owned subsidiary of AMID (“Merger Sub”). The Merger Agreement provides that we will be merged with Merger Sub (the “Merger”), with the Partnership surviving the merger as a wholly owned subsidiary of AMID.

Simultaneously with the execution of the Merger Agreement, on October 31, 2017, AMID and AMID GP entered into a Contribution Agreement (the “Contribution Agreement”) with Holdings. Upon the terms and subject to the conditions set forth in the Contribution Agreement, Holdings will contribute its equity interests in a new wholly owned subsidiary, which will hold substantially all the current subsidiaries (Southcross Holdings Intermediary LLC, a Delaware limited liability company, Southcross Holdings Guarantor GP LLC, a Delaware limited liability company, and Southcross Holdings Guarantor LP, a Delaware limited partnership, which in turn directly or indirectly own 100% of the limited liability company interest of our General Partner and 54.5% of the Partnership’s common units) and business of Holdings, to AMID and AMID GP in exchange for (i) the number of common units representing limited partner interests in AMID (each an “AMID Common Unit”) equal to $185,697,148, subject to certain adjustments for cash, indebtedness, working capital and transaction expenses contemplated by the Contribution Agreement, divided by $13.69, (ii) 4.5 million new Series E convertible preferred units of AMID (the “AMID Preferred Units”), (iii) options to acquire 4.5 million AMID Common Units (the “Options”), and (iv) 15% of the equity interest in AMID GP (the transactions contemplated thereby and the agreements ancillary thereto, the “Contribution” and, together with the Merger, the "Transaction").

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received by Holdings will be deposited into escrow in order to secure the potential indemnification obligations until the longer of the end of 12 months from the closing of the Contribution Agreement, May 31, 2019 or the final resolution of the Special Indemnity Matters (as defined in the Contribution Agreement). In addition, all of the AMID Common Units, AMID Preferred Units and the Options received by Holdings as consideration under the Contribution Agreement will be subject to a lock-up agreement whereby such securities will be locked up until the longer of 12 months (with respect to the AMID Common Units) and 24 months (with respect to the AMID Preferred Units and Options) and, together with the AMID GP equity interests, the final resolutions of the Special Indemnity Matters (as defined in the Contribution Agreement). Further, during this time, cash distributions made by AMID or AMID GP to Holdings will be restricted, must remain within Holdings, and will be subject to recapture by AMID. The closing under the Contribution Agreement is conditioned upon, among other things: (i) expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the”HSR Act”), which was received on December 8, 2017, (ii) the absence of certain legal impediments prohibiting the transactions and (iii) with respect to AMID’s obligation to close only, the conditions precedent contained in the Merger Agreement having been satisfied and the Merger having become effective substantially concurrently with the closing of the Contribution Agreement.

The Contribution Agreement contains provisions granting both parties the right to terminate the Contribution Agreement for certain reasons. The Contribution Agreement further provides that, upon termination by Holdings of the Contribution Agreement in the event of a Funding Failure (as defined in the Contribution Agreement), AMID may be required to pay Holdings a reverse termination fee in an amount up to $17 million.

Merger Agreement. On October 31, 2017, we and our General Partner entered into the Merger Agreement with AMID and AMID GP. At the effective time of the Merger, each common unit of the Partnership issued and outstanding or deemed issued and outstanding as of immediately prior to the effective time, will be converted into the right to receive 0.160 (the “Exchange Ratio”) of an AMID Common Unit, except for those common units held by affiliates of the Partnership and our General Partner, which will be cancelled for no consideration. Each of our common units, subordinated units and Class B Convertible Units held by Holdings, or any of its subsidiaries, issued and outstanding as of the effective time, will be canceled for no consideration in connection with the closing of the Merger. The incentive distributions rights held by our General Partner outstanding immediately prior to the effective time will be cancelled for no consideration in connection with the closing of the Merger.

Completion of the Merger is subject to the satisfaction of customary closing conditions, including (i) receipt of required regulatory approvals in connection with the Merger, including the expiration or termination of any applicable waiting period under the HSR Act and effectiveness of a registration statement on Form S-4 registering the AMID Common Units to be issued in connection with the Merger, (ii) the absence of certain legal impediments prohibiting the Merger Agreement and the transactions contemplated thereby, (iii) the closing of the Contribution in accordance with the terms of the Contribution Agreement and (iv) holders of at least a majority of our outstanding common units that are not held by our General Partner or its affiliates, holders of at least a majority of the outstanding subordinated units, voting as a class, and holders of at least a majority of the Class B Convertible Units, voting as a class, for the approval of the Merger Agreement and the transactions contemplated thereby.

The Merger Agreement contains customary termination rights for both the Partnership and AMID. The Merger Agreement further provides that, upon termination of the Merger Agreement, under certain specified circumstances, the Partnership may be required to reimburse AMID’s expenses, subject to certain limitations, up to $0.5 million (“AMID Expenses”) or to pay AMID a termination fee of $2.0 million less any previous AMID expenses reimbursed by the Partnership (the “Termination Fee”).

Letter Agreement. In connection with the Merger Agreement and Contribution Agreement, Holdings and the Partnership entered into a Letter Agreement (the “Letter Agreement”) providing that Holdings will reimburse the Partnership for all fees or expenses of the Partnership in connection with the Merger Agreement including (i) any fees or expenses of counsel, accountants, investment bankers and consultants retained by the Partnership or the conflicts committee of the Partnership, and (ii) the payment of any Termination Fee or the reimbursement of any AMID Expense, in each case if the Merger has not closed and (a) the Merger Agreement is terminated because the Contribution Agreement has been terminated under certain specified circumstances or (b) the Merger Agreement is terminated without the prior approval of the conflicts committee of the Partnership under certain specified circumstances.

On November 28, 2017, AMID and the Partnership filed Notification and Report Forms with the Antitrust Division of the Department of Justice and the Federal Trade Commission. On December 8, 2017, AMID and the Partnership received early termination of the applicable waiting period under the HSR Act.

On January 11, 2018, AMID filed with the SEC a Registration Statement on Form S-4 (file no. 333-222501) that includes a Proxy Statement of the Partnership and a Prospectus of AMID (the “Proxy Statement”). The S-4 has been declared effective

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and the Proxy Statement has been mailed to unitholders of the Partnership. We have scheduled a special meeting of our unitholders to be held on Tuesday, March 27, 2018, at 10:00 a.m., central time, at the Houston offices of Locke Lord LLP, JPMorgan Chase Tower, 600 Travis Street, Suite 2800, Houston, TX 77002, to consider and vote upon the proposed Merger and related matters pursuant to the Merger Agreement.

For additional information about the Merger Agreement with AMID, see our Proxy Statement.

On December 29, 2016, we entered into the fifth amendment (the “Fifth Amendment”) to the Third Amended and

Restated Revolving Credit Agreement with Wells Fargo, N.A., UBS Securities LLC, Barclays Bank PLC and a syndicate of

lenders (the "Third A&R Revolving Credit Agreement"), pursuant to which we received a full waiver for all defaults or events

of default arising out of our failure to comply with the financial covenant to maintain a Consolidated Total Leverage Ratio (as

defined in the Fifth Amendment) less than 5.00 to 1.00 for the quarter ended September 30, 2016.

Additionally, pursuant to the Fifth Amendment, (i) total aggregate commitments under the Third A&R Revolving Credit Agreement were reduced from $200 million to $135 million (then further reduced to $125 million on March 31, 2018) and the sublimit for letters of credit also was reduced from $75 million to $50 million (total aggregate commitments will be periodically further reduced through December 31, 2018 to $115 million); (ii) the Consolidated Total Leverage Ratio and Consolidated Senior Secured Leverage Ratio (each as defined in the Fifth Amendment) financial covenants were suspended until the quarter ended March 31, 2019; and (iii) the Consolidated Interest Coverage Ratio (as defined in the Fifth Amendment) financial covenant requirement was reduced from 2.50 to 1.00 to 1.50 to 1.00 for all periods ending on or prior to December 31, 2018 (the “Ratio Compliance Date”). Prior to the Ratio Compliance Date, we will be required to maintain minimum levels of Consolidated EBITDA (as defined in the Fifth Amendment) on a quarterly basis and be subject to certain covenants and restrictions related to liquidity and capital expenditures. See Note 6 to our consolidated financial statements.

In connection with the execution of the Fifth Amendment, on December 29, 2016, the Partnership entered into (i) an

Investment Agreement (the "Investment Agreement") with Holdings and Wells Fargo Bank, N.A., (ii) a Backstop Agreement

(the "Backstop Agreement") with Holdings, Wells Fargo Bank, N.A. and the Sponsors and (iii) a First Amendment to the equity

cure contribution agreement (the "Equity Cure Contribution Amendment") with Holdings. Pursuant to the Equity Cure

Contribution Amendment, on December 29, 2016, Holdings contributed $17.0 million to us in exchange for 11,486,486 common units. The proceeds of the $17.0 million contribution were used to pay down the outstanding balance under the Third A&R Revolving Credit Agreement and for general corporate purposes. On January 2, 2018, we notified Holdings that a Full Investment Trigger (as defined in the Investment Agreement) occurred on December 31, 2017. Pursuant to the Backstop Agreement, on January 2, 2018, Holdings delivered a Backstop Demand (as defined in the Investment Agreement) for each Sponsor to fund their respective pro rata portions of the Sponsor Shortfall Amount (as defined in the Investment Agreement) of $15.0 million in accordance with the Backstop Agreement. As consideration for the amount provided directly to us by a Sponsor pursuant to the Backstop Agreement, we issued to the Sponsors senior unsecured notes of the Partnership in an aggregate principal amount of $15.0 million (each, an "Investment Note" and collectively, the “Investment Notes”). The Investment Notes mature on November 5, 2019 and bear interest at a rate of 12.5% per annum. Interest on the Investment Note shall be paid in kind (other than with respect to interest payable (i) on or after the maturity date, (ii) in connection with prepayment, or (iii) upon acceleration of the Investment Note, which shall be payable in cash); provided that all interest shall be payable in cash on or after December 31, 2018. The Investment Notes are the unsecured obligation of the Partnership subordinate in right of payment to any of our secured obligations under the Third A&R Revolving Credit Agreement.

Hurricane Harvey

We began preparing our South Texas Gulf Coast assets for the impact of Hurricane Harvey prior to the storm’s landfall in

late August 2017 to maintain the safety of our facilities, our neighbors and our employees. Fortunately, our Gulf Coast assets

sustained only minor wind and flood damage as a result of the storm. These facilities resumed operation within a few days after

third party electrical power was restored to them. Our South Texas assets located further inland were temporarily shut-in

because our downstream sales markets for both natural gas and NGLs were closed for a short period of time. Over 90% of our

South Texas gas supply and downstream sales markets resumed normal operations by early September 2017, and full pre-storm

operations were achieved by the end of September 2017. Our Mississippi and Alabama assets were not impacted by Hurricane

Harvey.

Distribution Suspension

The board of directors of our General Partner suspended paying a quarterly distribution with respect to the fourth quarter of 2015 and every quarter of 2016 and 2017 to conserve any excess cash for the operation of our business. The board of directors of our General Partner and our management believe this suspension to be in the best interest of our unitholders and will continue to evaluate our ability to reinstate the distribution in future periods. More importantly, we are restricted under the

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terms of the Merger Agreement and the Fifth Amendment from paying a distribution until our Consolidated Total Leverage Ratio is below 5.0. See Notes 2 and 3 to our consolidated financial statements.

Ownership Structure

The following table depicts our ownership structure as of December 31, 2017:



Description	Percentage ownership
Ownership by non-affiliates:
Public common units	27.4	%
Southcross Holdings LP's ownership:
Common units	32.8	%
Subordinated units	15.1	%
Class B Convertible Units	22.7	%
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 increasing the reliability and efficiency of our assets while managing our costs to ensure the ongoing stability of our business. We expect to achieve this objective by pursuing the following business strategies:


•	Maintain sound financial practices to ensure our long-term viability. We intend to maintain our commitment to financial discipline, including reduction of leverage on our consolidated balance sheet, which we believe will serve the long-term interests of our unitholders.

•

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 such as adding new natural gas supplies to our existing gathering and processing assets and pursuing new supplies of NGLs for our fractionation facilities. We have seen an increase in drilling activity around our South Texas assets since 2016 which we believe will lead to improved opportunities for us.

•

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. Also, we will consider other methods of limiting commodity exposure, including the use of derivative instruments, as appropriate.


•	Continue cost savings initiatives. We intend to continue to evaluate and implement cost-saving initiatives to improve and generate future cash flows.

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 operate in Mississippi and Alabama. Also, 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. Our growth opportunities are impacted primarily by natural gas production in the 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 South Texas 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 for both natural gas and NGLs in and around the Corpus Christi area.

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•

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 access to NGL fractionation and transportation services. 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 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, which is the owner of our General Partner and the indirect beneficial owner of 54.5% of our common units, 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 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, two natural gas processing plants, one fractionation facility, 20 compressor stations and a treating system. 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, 2017:



	As of December 31, 2017	Year Ended December 31, 2017
Gathering systems and intrastate pipelines	Miles	Average throughput volumes of natural gas (MMcf/d)
South Texas	2,016	442
Mississippi/Alabama	1,101	166
Total	3,117	608



	As of December 31, 2017	Year Ended December 31, 2017
Processing plants	Approximate design of gas processing capacity (MMcf/d)	Average volume of processed gas (MMcf/d)
Woodsboro	200	132
Lone Star	300	118
Total	500	250



	As of December 31, 2017	Year Ended December 31, 2017
Fractionation plants	Approximate design of fractionation capacity (Bbls/d)	Average volume of NGLs sold from output (Bbls/d)
Bonnie View (1)	22,500	3,380
Total	22,500	3,380

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	As of December 31, 2017
Field Compression Stations	Approximate design of compression horsepower
Gregory	4,480
Valley Wells Treater	21,100
El Dorado	8,100
Comet	5,400
Lancaster	4,830
Barracuda	4,800
Hornet	2,700
Corvair	2,700
Cyclone	2,700
Oppenheimer	1,300
Urban	500
Scott North	637
Other	2,421
Total	61,668

(1)

During the second quarter of 2017, in an effort to further our cost-saving initiatives, management elected to idle the Bonnie View fractionation facility (“Bonnie View”). As a result, all of our Y-grade product is sold to Holdings in accordance with our affiliate Y-grade sales agreement and is being fractionated at the Holdings’ Robstown fractionation facility (“Robstown”). We plan to utilize Bonnie View as a backup option to the extent Robstown is unable to fractionate our Y-grade product and, therefore, we plan to spend an immaterial amount of capital during 2018 to ensure Bonnie View remains available in the future.

We own equity interests in three joint ventures with Targa Resources Corp. ("Targa") as our joint venture partner. T2 Eagle Ford Gathering Company LLC (“T2 Eagle Ford”), T2 LaSalle Gathering Company LLC (“T2 LaSalle”) and T2 EF Cogeneration Holdings LLC (“T2 Cogen”) 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 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, 2017:



	As of December 31, 2017
Joint venture pipelines	Miles	Leased Capacity		Average throughput volumes of natural gas (MMcf/d)
Dimmit	49	50	%	14
LaSalle	63	25	%	166
Choke Canyon	72	50	%	203
Residue Header	76	50	%	236
Total	260

We derive revenue primarily from fixed-fee and fixed-spread arrangements. 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:

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•

Ethane. Ethane is typically supplied as purity ethane or as part of an ethane-propane mix. Ethane is used primarily 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 typically is 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. In addition, U.S. demand for propane as a heating fuel is affected significantly by weather conditions. The volume of propane sold in the U.S. typically is 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. U.S. demand for normal butane as a refined product blending component is at its highest in September through February. 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 affect demand for normal butane adversely.


•	Isobutane. Isobutane is used predominantly 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 affect demand for natural gasoline adversely.

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 affect demand for the services we provide adversely as well as NGL prices, which would impact negatively our results of operations and financial condition.

South Texas

The assets in our South Texas region are located between Webb and Dimmit Counties near the Texas-Mexico border. As of December 31, 2017, these assets consisted of approximately 2,016 miles of pipeline ranging in diameter from 2 to 24 inches, our Woodsboro processing plant, our Bonnie View NGL fractionation facility, our Lone Star processing plant, our Valley Wells System and 20 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 and Bonnie View. 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. Holdings owns approximately 805 miles of pipeline, most of which is in Frio and LaSalle counties, and the Robstown fractionator ("Robstown") to which all of our South Texas assets are connected.

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 June 2015, we completed the NGL pipelines, which include a Y-grade pipeline that connects our Woodsboro processing facility to 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 capacity reductions 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 Southcross TS Midstream Services, LP in August 2014. The plant is interconnected with other South Texas rich gas supply basins and Woodsboro via our Bee Line pipeline which was placed into service in 2013.

Our Gregory processing plant was 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 processed natural gas from both a local gathering system and from sources elsewhere on our South Texas pipeline systems until we determined, as part of cost-

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cutting initiatives, to idle the plant in August 2016. In December 2016, we shut down and converted our Gregory cryogenic processing plant into a compressor station. The natural gas that previously was sent to Gregory has been diverted to our newer, more efficient, Woodsboro plant. The conversion of the Gregory plant resulted in operating expense and capital expense savings. During the year ended December 31, 2017, we sold $2.1 million of the assets associated with Conroe and Gregory. As a result, we recorded an impairment of $1.1 million during the year ended December 31, 2017, to adjust the carrying value of these assets to fair value.

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 started one of the Gregory plants and operated it until it was permanently idled in August 2016. In December 2016, we reached a settlement related to the Gregory processing plant fire with our insurance carriers. We received the payment of $2.0 million from our insurance carriers in the first quarter of 2017 and recorded a $1.5 million gain related to insurance proceeds received in excess of expenditures incurred to repair Gregory. As stipulated in the Term Loan Agreement (defined in Note 6 to our consolidated financial statements), we used $1.0 million ($2.0 million of proceeds, net of the 2015 insurance deductible of $0.5 million and additional expenditures to repair Gregory of $0.5 million) of the proceeds to make a mandatory prepayment on our term loan.

Our Conroe processing plant and gathering system was a 50 MMcf/d cryogenic natural gas plant. The processing plant and gathering system operated together north of Houston in Montgomery County, Texas to gather and process natural gas. We had 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 was returned to the producers for gas lift purposes. We sold the remaining residue gas and NGLs to unaffiliated parties.

We decided to shut down the Conroe facility as part of company-wide, cost-cutting initiatives. On July 29, 2016, we notified our producers that the Conroe plant was going to be shut down by year end. In December 2016, the Conroe plant was shut down and was dismantled as of December 31, 2017.

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 611 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.

The assets in our Alabama region are located in northwest and central Alabama and consist of 490 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. and Targa Resources Corp.

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.

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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 affected similarly 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 46.4% of our revenue for the year ended December 31, 2017. Due to the continued volatility of commodity prices, some of our customers may experience material financial and liquidity issues. For the years ended December 31, 2017 and 2016, we did not experience significant nonpayment for services. We had no allowance for uncollectible accounts receivable at December 31, 2017. We recorded an allowance for uncollectible accounts receivable of $0.1 million at December, 31, 2015 which was written off in 2016.

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 Protecting Our Infrastructure of Pipelines and Enhancing Safety (PIPES) Act of 2016, signed on June 22, 2016, provides funding for the continuation of pipeline safety program revisions initiated under the 2011 Pipeline Safety Act and requires PHMSA to set minimum safety standards for underground natural gas storage facilities, authorizes emergency order authority, designates marine coastal areas as unusually environmentally sensitive to pipeline failures and requires additional safety studies that could result in new regulatory requirements for existing pipelines.

PHMSA issued a separate rule effective on March 24, 2017 that imposes pipeline incident prevention and response measures on pipeline operators. PHMSA also published an advisory bulletin in 2012 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 from time to time has recommended that the PHMSA make changes to its rules, including removing an exemption from most safety inspections for natural gas pipelines installed before 1970. While we cannot predict the outcome of proposed legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our operations, particularly by extending more stringent and comprehensive safety regulations (such as integrity management requirements) to pipelines and gathering lines not previously subject to such requirements. Further legislative and regulatory changes may also result in higher penalties for the violation of federal pipeline safety regulations. While we expect any legislative or regulatory changes to allow us time to become compliant with new requirements, costs associated with compliance may have a material effect on our operations. We cannot predict with any certainty at this time the terms of any new laws or rules or the costs of compliance associated with such requirements, but we regularly inspect our pipelines and third parties assist us in interpreting the results of the inspections.

States largely are 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

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of workers, both generally and within the pipeline industry; the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and citizens; 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. 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, even fatal, 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 relating to these and other issues 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., Southcross Transmission, LP, Southcross Nueces Pipelines LLC and Southcross Alabama Pipeline LLC, also provide certain interstate transportation services. The rates, terms and conditions of such services are subject to the jurisdiction of the Federal Energy Regulatory Commission ("FERC") under Section 311 of the Natural Gas Policy Act of 1978 ("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 by FERC are maximum and minimum rates and we may negotiate discounts at or below such maximum rates (but above the minimum 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. On November 6, 2017, in FERC Docket No. PR18-6-000, Southcross Transmission, LP filed a petition for rate approval and amended statement of operating conditions in accordance with the required rate review. As of January 5, 2018, the rate filing was deemed approved. The next rate review, which is for Southcross Mississippi Pipeline, L.P., occurs in 2019. 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 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 that originates 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

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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

Interstate natural gas pipelines regulated by FERC are required to comply with numerous regulations related to standards of conduct, market transparency, and market manipulation. FERC’s standards of conduct regulate the manner in which interstate natural gas pipelines may interact with their marketing affiliates. FERC’s market oversight and transparency regulations require regulated entities to submit reports of, among other things, threshold purchases or sales of natural gas and publicly post certain information on scheduled volumes. FERC’s market manipulation regulations, promulgated pursuant to the Energy Policy Act of 2005 (the “EPAct 2005”), make it unlawful for any entity, 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 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 EPAct 2005 also amends the NGA and the NGPA to give FERC authority to impose civil penalties for violations of these statutes up to $1.0 million per day per violation for violations occurring after August 8, 2005. The maximum penalty authority established by the statute has been and will continue to be adjusted periodically for inflation. Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

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

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Southcross 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. a utility and it is necessary to get contract approval for negotiated contracts.

In Alabama, the Alabama Public Service Commission ("APSC") requires a gas utility to file "special negotiated contracts" with the APSC for approval, which includes our Southcross Alabama Pipeline LLC.

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

Sales of Natural Gas and NGLs

The transportation of natural gas in interstate commerce is regulated by FERC under the NGA, the NGPA and regulations issued under those statutes and the transportation of NGLs in interstate commerce is 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 transportation of natural gas 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. On July 20, 2016, DHS published a Final Rule outlining DHS’s tiering methodology to incorporate relevant elements of risk used to identify high risk facilities. Covered facilities that are determined by DHS to pose a high level of security risk are 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. Two of our facilities (the Gregory 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.

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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 is subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:


•	requiring the installation of pollution-control equipment or otherwise restricting the way we operate or imposing additional costs on our operations;


•	managing or otherwise regulating the way we handle and secure toxic, reactive, flammable or explosive materials to prevent or minimize the release of such materials;


•	limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;


•	delaying system modification or upgrades during permit reviews;


•	requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former or third-party operations; and


•	enjoining the operations of facilities deemed to be in non-compliance with permits issued pursuant to or permit requirements imposed by such environmental laws and regulations.

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 and pursuit of injunctive relief. 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 materials 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, regulations, 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, release and disposal of hazardous substances and solid and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where these materials 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.

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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 certain non-hazardous waste, 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 management and disposal requirements. Moreover, from time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for non-hazardous wastes, including natural gas wastes. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses or otherwise impose limits or restrictions on our operations or those of our customers.

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

Oil Pollution Act

In 1991, the EPA adopted regulations under the Oil Pollution Act (the "OPA"). These oil pollution prevention regulations, as amended several times since their original adoption, require the preparation of a Spill Prevention Control and Countermeasure ("SPCC") plan 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 emission 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. 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. Although this rule has been the subject of litigation and may be revised, we do not anticipate that the revisions will have a material adverse effect on our operations. The few engines we do have that are subject to the control and compliance provisions of National Emission Standards for Hazardous Air Pollutants Standard are new engines which meet the emissions limitations therein.

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

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transmission, which, among other things, adjusted reporting requirements and phased in the date by which storage tanks must install VOC controls. On June 3, 2016, the EPA published additional regulations to control emissions of methane and VOCs from various oil and natural gas operations, although on June 16, 2017, the EPA proposed to stay for 2 years certain requirements in the final rule including those relating to fugitive emissions requirements, well site pneumatic pump requirements, and requirements for certification of closed vent systems by a professional engineer. Litigation continues regarding the rules and stays. Compliance with these rules, if they are not stayed, 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. In May 2015, the EPA issued a final rule that attempts to clarify the federal jurisdictional reach over waters of the U.S., but this rule has been stayed nationwide by the U.S. Sixth Circuit Court of Appeals. On January 13, 2017, the U.S. Supreme Court agreed to review the Sixth Circuit’s finding that it has jurisdiction to hear challenges to the rule. In addition, in June 2017, the EPA and U.S. Army Corps of Engineers proposed a rule to rescind the May 2015 rule, and re-codify the regulatory test that existed prior to 2015 regarding the definition of “Waters of the United States.” To the extent, if at all, the May 2015 rule becomes effective, and thus expands the scope of the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. We believe that compliance with existing permits and compliance with foreseeable new permit requirements under the Clean Water Act and state counterparts will not have a material adverse effect on our 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 greenhouse gas ("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 GHG emissions from certain large GHG emissions sources. Our Gregory, Woodsboro, Bonnie View, 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. In addition, on June 3, 2016, the EPA issued published regulations to control emissions of methane, a GHG, and VOCs from various oil and natural gas operations, although on June 16, 2017, the EPA proposed to stay for 2 years certain requirements in the final rule. Litigation continues regarding the rules and the stays. Compliance with these rules, if they are not stayed, could result in additional costs, including increased capital expenditures and operating costs, for us and our customers which may adversely impact our business.

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. Several states have 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

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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 GHG emissions (the “Paris Agreement”). On June 1, 2017, however, President Trump announced that the United States would withdraw from the Paris Agreement unless it could re-enter on more favorable terms. We continue to monitor the international efforts to address climate change. To the extent the United States and other countries implement the Paris Agreement, or a replacement accord, 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 GHG emitting energy sources, our products would become more desirable in the market with more stringent limitations on GHG emissions. To the extent that our products are competing with lower GHG 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 could have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events, and effects upon sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our operations and those of our customers, have the potential to be affected adversely. Potential adverse effects could include disruption of our activities, including, for example, damages to our facilities from powerful winds or floods, or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the operations of our customers, and the service companies or suppliers with whom we have a business relationship. Our operations along the Gulf Coast are vulnerable to operational and structural damages resulting from hurricanes and other severe weather systems and our insurance may not cover all associated losses. We are taking steps to mitigate physical risks from storms, but no assurance can be given that future storms will not have a material adverse effect on our business.

Employees

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 214 full-time employees as of December 31, 2017. None of these employees are covered by collective bargaining agreements, and our General Partner considers its employee relations to be good.

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 Securities Exchange Commission (the "SEC") under 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 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.

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., Washington, DC 20549 on official business days during the hours of 10 a.m. to 3 p.m. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-(800) SEC-0330.

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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 Form 10-K, 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 reinstate paying the minimum quarterly distribution, or any distribution, to our unitholders.

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, each quarter to enable us to reinstate the minimum quarterly distribution. For example, in January 2016 the board of directors of our General Partner suspended paying a quarterly distribution with respect to the fourth quarter of 2015 and every quarter of 2016 and 2017 and instead, based on current conditions, to conserve any excess cash for the operation of our business. Additionally, we currently have restrictions on paying a cash distribution until our Consolidated Total Leverage Ratio is below 5.0 to 1.0. Finally, the Merger Agreement restricts us from paying distributions at this time. The board of directors of our General Partner and our management believe this suspension to be in the best interest of our unitholders and will continue to evaluate the Partnership's ability to reinstate the distribution in future periods. 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;

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•	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.

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 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.

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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 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 because our producer customers are often unwilling to share this information for competitive reasons. 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 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 from time to time in the planning and construction of development projects, some of which may 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 types of 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;

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


•	the levels of domestic production and consumer demand;


•	the availability of transportation systems with adequate capacity;


•	the volatility and uncertainty of regional pricing differentials;


•	the price and availability of alternative fuels;


•	the effect of energy conservation measures;


•	the nature and extent of governmental regulation and taxation;


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


•	the anticipated future prices of 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

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face increased exposure to commodity price risks, which in turn could result in increased volatility in our revenue, gross operating margin and cash flows.

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

We compete with other similarly sized midstream companies in our areas of operation. Some of our competitors are large companies that have greater financial, managerial and other resources than we do. In addition, some of our competitors have assets in closer proximity to natural gas supplies and have available idle capacity in existing assets that would not require new capital investments for use. Our competitors may expand or construct gathering, compression, treating, processing or transportation systems or 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 46.4% of our revenue for the year ended December 31, 2017. 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

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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.

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 may 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 may 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.

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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, (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. Under the terms of the Merger Agreement, we are restricted from making acquisitions at this time.

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.

Incremental projects require access to new capital. Tightened capital markets or increased competition for investment opportunities could impair our ability to finance such projects.

We continuously consider and enter into discussions regarding potential acquisitions or capital expenditures. Any limitations on our access to new capital will impair our ability to execute these projects. 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 finance future projects.

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 business 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

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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 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.

Our debt may limit our flexibility to obtain financing and to pursue other business opportunities.

As of December 31, 2017, we had total principal indebtedness of $548.6 million, comprised of $429.1 million related to our term loan and $119.5 million (including outstanding letters of credit) related to our revolving credit facility, which had $15.5 million remaining in unused 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;


•	our flexibility in responding to changing business and economic conditions may be limited; and


•	its effect on the going concern ("Going Concern") issue past the next twelve months as we will not be in compliance with our consolidated total leverage ratio set at 5.0 to 1.0.

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

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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;


•	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 metrics. Our ability to meet those financial metrics and tests can be affected by events beyond our control, and we cannot provide assurance that we will meet those metrics and tests. On December 29, 2016, we entered into the fifth amendment to the Third A&R Revolving Credit Agreement (the “Fifth Amendment”), pursuant to which we received a full waiver for all defaults or events of default arising out of our failure to comply with the financial covenant to maintain a Consolidated Total Leverage Ratio less than 5.00 to 1.00 for all periods ending on or prior to December 31, 2018 (the "Ratio Compliance Date"). 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 6 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.

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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. For example, as discussed in Note 2, we do not expect to be in compliance with the Consolidated Total Leverage Ratio (as defined in the Fifth Amendment) at March 31, 2019 which begins the uncertainty of our ability to continue as a going concern as early as the end of the first quarter of 2018. As a result, 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 6 to our consolidated financial statements, could terminate their commitments to loan money, and the lenders could foreclose against our assets 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. Based upon the Partnership's financial forecast, the Fifth Amendment, as well as the $15.0 million provided by the Sponsors in exchange for senior unsecured notes of the Partnership, we believe management's executed plans provide the Partnership with sufficient liquidity to fund future operations through at least twelve months from the date that our 2017 financial statements were issued.

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 GHG emissions from certain large GHG emissions sources. Our Gregory, Woodsboro, Bonnie View, 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. In

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addition, on June 3, 2016, the EPA published regulations to control emissions of methane, a GHG, and VOCs from various oil and natural gas operations, although on June 16, 2017, the EPA proposed to stay for 2 years certain requirements in the final rule. Litigation continues regarding the rules and the stays. Compliance with these rules, if they are not stayed, could result in additional costs, including increased capital expenditures and operating costs, for us and our customers which may adversely impact our business.

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. 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 GHG emissions (the "Paris Agreement"). On June 1, 2017, however, President Trump announced that the United States would withdraw from the Paris Agreement unless it could re-enter on more favorable terms. 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.

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, and effects upon sea

levels, the arability of farmland, and water availability and quality. If such effects were to occur, our operations and those of our

customers, have the potential to be adversely affected. Potential adverse effects could include disruption of our activities,

including, for example, damages to our facilities from powerful winds or floods, or increases in our costs of operation or

reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverage in the aftermath of

such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by

disrupting the operations of our customers, and the service companies or suppliers with whom we have a business relationship. 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.

Furthermore, a number of public and private studies are underway regarding the connection, if any, between

the disposal of waste water associated with hydraulic fracturing and observed seismicity in the vicinity of such disposal

operations. Several states, municipalities and local regulatory bodies have also proposed or adopted, or are considering, legislative or regulatory restrictions on hydraulic fracturing, including in some cases by imposing moratoria on hydraulic

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fracturing or regarding permitting, casing and cementing of wells; testing of nearby water wells; restrictions on access to, and

usage of, water; and restrictions on the type of chemical additives that may be used in hydraulic fracturing operations. 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, state or local 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 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 natural gas transportation facilities that do not provide interstate transmission services, and natural gas 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 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

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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:


•	perform ongoing assessments of pipeline integrity;


•	identify and characterize applicable threats to pipeline segments that could impact a high consequence area;


•	maintain processes for data collection, integration and analysis;


•	repair and remediate pipelines as necessary; and


•	implement preventive and mitigating actions.

In addition, many states, including the states in which we operate, have adopted regulations similar to existing DOT regulations for intrastate pipelines. Although many of our pipeline facilities fall within a class that is currently not subject to these requirements, we may incur significant costs and liabilities associated with repair, remediation, preventative or mitigation measures associated with our non-exempt pipelines, particularly in South Texas. We have incurred costs of approximately $0.9 million and $0.8 million during the years ended December 31, 2017 and 2016, 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 2017 and 2016 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.

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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.

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.

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.

In February 2017, the U.S. President ordered the Secretary of the U.S. Treasury to review certain existing rules and regulations, such as those promulgated under the Dodd-Frank Act; however, the implications of that review are not yet known and none of the rules and regulations promulgated under the Dodd-Frank Act have been modified or rescinded as of the date of this report. Given the uncertainty associated with both the results of the existing Dodd-Frank Act requirements and the manner in which additional provisions of the Dodd-Frank Act will be implemented by various regulatory agencies and through regulations, the full extent of the impact of such requirements on our operations is unclear. Accordingly, the changes resulting from the Dodd-Frank Act may impact the profitability of business activities, require changes to certain business practices, or otherwise adversely affect our financial condition, results of operations, cash flows, and our ability to satisfy our debt service obligations and to make cash distributions to our unitholders.

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

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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 General Partner's 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 senior executives and key personnel or attract and retain qualified personnel in the future. Our failure to retain or attract 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 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 of the Sarbanes-Oxley Act. As a smaller reporting company, as defined in Rule 12b-2 of the Securities Exchange Act of 1934, our independent registered public accounting firm is not required to attest annually to the effectiveness of our internal control over financial reporting.

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.

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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 that received membership interests in Holdings in connection with Holdings’ Chapter 11 reorganization. David W. Biegler served as the chairman of the board of our General Partner through January 6, 2017, at which time Bruce A. Williamson was appointed chairman of the board of our General Partner. 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.

•

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.

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


•	Our Partnership Agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.


•	Our General Partner 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.

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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.

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, neither 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 22,122,113 publicly traded common units as of December 31, 2017. In addition, Holdings owned 26,492,074 common units, 12,213,713 subordinated units and 18,335,181 Class B Convertible Units as of December 31, 2017. You may not be able to resell your common units at or above your acquisition price. Additionally, a lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

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 (or any suspension thereof);


•	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

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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. 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 February 23, 2018, Holdings, the 100% owner of our General Partner, owned, indirectly, 54.5% of the outstanding common units, 100% of our outstanding subordinated units and 100% of our outstanding Class B Convertible Units.

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 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.

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;

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•	whether to elect to reset target distribution levels;


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


•	whether or not to consent to any merger or consolidation of the Partnership or amendment to the Partnership Agreement.

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

Our Partnership Agreement restricts the rights of holders of our common and subordinated units with respect to actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.

Our Partnership Agreement contains provisions that restrict the rights of unitholders with respect to actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our Partnership Agreement provides that:

•

whenever our General Partner makes a determination or takes, or declines to take, any other action in its capacity as our General Partner, our General Partner is required to make such determination, or take or decline to take such other action, in good faith, meaning it subjectively believed that the decision was in the best interest of us and our unitholders, and except as specifically provided by our Partnership Agreement, will not be subject to any other or different standard imposed by our Partnership Agreement, Delaware law, or any other law, rule or regulation, or at equity;


•	our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a General Partner so long as such decisions are made in good faith;

•

our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in 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, though we currently have a three member committee of 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.

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

Our General Partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election by our General Partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

We anticipate that our General Partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our General Partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our General Partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our General Partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for our General Partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then-current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our General Partner in connection with resetting the target distribution levels related to our General Partner’s incentive distribution rights.

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

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders have no right on an annual or ongoing basis to elect our General Partner or its board of directors. The board of directors of our General Partner will be chosen by 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 February 23, 2018, Holdings indirectly owns an approximate 72.2% 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

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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.

Subject to the terms of the Merger Agreement, we may issue additional units without your approval, which would dilute your existing ownership interests. For example, in connection with the Fifth Amendment, our parent made a $17 million contribution to us to pay down the outstanding balance under the Third A&R Revolving Credit Agreement and for general corporate purposes, in exchange for 11,486,486 common units, which diluted 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 our 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 February 23, 2018, Holdings held an aggregate of 26,492,074 common units, 12,213,713 subordinated units and 18,656,071 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, when we generate class B distributable cash flow, and paid, the declared distribution on all outstanding units for the two prior quarters, and when 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 February 23, 2018, Holdings owned 54.5% of our 48,623,615 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 72.2% of our outstanding common units.

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

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


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


•	your right to act with other unitholders to remove or replace our General Partner, to approve some amendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitute "control" of our business.

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

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

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. Under the terms of the Merger Agreement, we are restricted from making acquisitions at this time.

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.

Risks Related to our Common Units

We may not be able to continue to comply with the New York Stock Exchange's requirements for continued listing.

No assurances can be made that we will in fact be able to continue to comply and that our common units will remain listed on the New York Stock Exchange ("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, 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 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. The issuance and sale of substantial amounts of common units or the announcement that such issuances and sales may occur, could adversely affect the market price of our common units.

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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 21%, 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.

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.

On January 24, 2017, the U.S. Treasury Department and the IRS published final regulations regarding qualifying income under Section 7704(d)(1)(E) of the Code. We do not believe these regulations adversely affect our status as a partnership for federal income tax purposes.

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.

The effects of the budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act (hereinafter, “Tax Cuts

and Jobs Act”) on our business have not yet been fully analyzed and could have an adverse effect on our net income.

On December 22, 2017, the Tax Cuts and Jobs Act was signed into law and made significant changes to the U.S. Internal

Revenue Code. Such changes include a reduction in the corporate and individual tax rates and limitations on certain deductions

and credits, among other changes. Certain of these changes could have a negative impact on our business. In addition, adverse

changes in the underlying profitability and financial outlook of our operations or changes in tax law could lead to changes in our valuation allowances against deferred tax assets on our consolidated balance sheets, which could materially affect our results of operations. We are in the process of analyzing the Tax Cuts and Jobs Act and its possible effects on us.

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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.

We may engage in transactions to de-lever the Partnership and manage our liquidity that may result in income and gain to our unitholders. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale. Further, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” (also referred to as “COD income”) being allocated to our unitholders as taxable income. Unitholders may be allocated COD income, and income tax liabilities arising therefrom may exceed cash distributions. The ultimate effect of any such allocations will depend on the unitholder's individual tax position with respect to its units. Unitholders are encouraged to consult their tax advisors with respect to the consequences of potential COD income or other transactions that may result in income and gain to unitholders.

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.

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 we will be able to do so (and will choose to do so) under all circumstances, or that we will be able to (or choose to) effect corresponding shifts in state income or similar tax liability resulting from the IRS adjustment in states in which we do business in the year under audit or in the adjustment year. If we are unable (or otherwise fail to choose) 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

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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 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.

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.

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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.

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.

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.

Risks Relating To The Merger

AMID and the Partnership may be unable to obtain the regulatory clearances required to complete the Merger or, in order to do so, AMID and the Partnership may be required to comply with material restrictions or satisfy material conditions.

AMID and the Partnership received early termination of the applicable waiting period under the HSR Act on December 8, 2017. The Merger may still be reviewed under antitrust statutes of other governmental authorities, including by state regulatory authorities such as the MPSC. The closing of the Merger is subject to the condition that there is no law, injunction, judgment or ruling by a governmental authority in effect enjoining, restraining, preventing or prohibiting the Merger. We can provide no assurance that all required regulatory clearances will be obtained. If a governmental authority asserts objections to the Merger, AMID or the Partnership may be required to divest assets in order to obtain antitrust clearance. There can be no assurance as to the cost, scope or impact of the actions that may be required to obtain antitrust or other regulatory approval. If we take such actions, it could be detrimental to us. These conditions or changes could also delay or materially and adversely affect our results of operations, financial condition, and cash flow.

State attorneys general could seek to block or challenge the Merger as they deem necessary or desirable in the public interest at any time, including after completion of the Transaction. In addition, in some circumstances, a third party could initiate a private action under antitrust laws challenging or seeking to enjoin the Merger, before or after it is completed. We may not prevail and may incur significant costs in defending or settling any action under the antitrust laws.

The Mississippi Public Services Commission (“MPSC”) requires that when a company proposes a change of control of a certificate of public convenience and necessity (“CPCN”), the company must obtain an order from the MPSC approving the sale and transfer of the CPCN. Southcross Mississippi Industrial Gas Sales, L.P., an indirect subsidiary of the Partnership, has a CPCN that, subject to the approval of the MPSC, will be transferred in connection with the Transaction. The MPSC could decide not to issue an order authorizing the transfer of the CPCN. Moreover, there is no guarantee that, if granted, such order will be granted in a timely manner or will be free from potentially burdensome conditions.

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In the event that the Merger Agreement is terminated prior to the completion of the Merger, we could incur significant transaction costs that could materially impact its financial performance and results of operations.

We will incur significant transaction costs, including legal, accounting, financial advisory, filing, printing, and other costs relating to the Merger. The Merger Agreement provides that upon termination of the Merger Agreement under certain specified circumstances, we will be required to pay all of the reasonable documented out-of-pocket expenses incurred by AMID in connection with the Merger Agreement and the transactions contemplated thereby up to a maximum amount of $500,000. In addition, if the Merger Agreement is terminated due to an adverse recommendation change by the Board of Directors of our General Partner having occurred, we may be required to pay AMID a termination fee of $2 million, less any expenses previously paid by the Partnership. We will also be required to pay AMID a termination fee in the event that we enter into an agreement with respect to an alternative proposal within 12 months after the date that the Merger Agreement is terminated for certain reasons if such alternative proposal was publicly proposed prior to the special meeting of our unitholders called with respect to the Merger or prior to the termination of the Merger Agreement in the event that such special meeting never occurred. Any fees due as a result of termination could have a material adverse effect on our results of operations, financial condition, and cash flows.

We may have difficulty attracting, motivating and retaining executives and other employees in light of the Merger.

Uncertainty about the effect of the Merger on our employees may have an adverse effect on us. This uncertainty may impair our ability to attract, retain and motivate personnel until the Merger is completed. Employee retention and recruitment may be particularly challenging prior to the completion of the Merger, as current and prospective employees may experience uncertainty about their future roles with the Partnership. In addition, we may have to provide additional compensation in order to retain employees. If key employees depart or fail to accept employment with the Partnership or our subsidiaries due to the uncertainty and difficulty of integration or a desire not to remain with us, our results of operations, financial condition, and cash flows could be adversely affected.

We are subject to business uncertainties and contractual restrictions while the Merger is pending, which could adversely affect our business and operations.

In connection with the pending Merger, it is possible that some customers, suppliers and other persons with whom we have business relationships may delay or defer certain business decisions or might decide to seek to terminate, change or renegotiate their relationship with us as a result of the Merger, which could negatively affect our revenues, earnings and cash available for distribution, as well as the market price of our common units, regardless of whether the Merger is completed.

In addition, the Merger Agreement restricts us and our subsidiaries, without AMID’s consent, from taking specified actions until the Merger occurs or the Merger Agreement is terminated, including, without limitation: (i) making certain acquisitions and dispositions of assets or property; (ii) exceeding certain capital spending limits; (iii) incurring certain forms of indebtedness; (iv) issuing equity or equity equivalents; and (v) making distributions. These restrictions may prevent us from pursuing otherwise attractive business opportunities or making other changes to our business prior to consummation of the Merger or termination of the Merger Agreement. Such limitations could negatively affect our businesses and operations prior to the completion of the Merger.

Furthermore, we expect that matters relating to the Merger and integration-related issues will place a significant burden on management, employees, and internal resources, which could otherwise have been devoted to other business opportunities. The diversion of management time on Merger-related issues could affect our financial results.

We are subject to litigation related to the proposed Merger.

In connection with the proposed Merger, purported unitholders of the Partnership have filed putative unitholder class action lawsuits against the Partnership, the Board of Directors of our General Partner and AMID, among others. Among other remedies, the plaintiffs seek to enjoin the transactions contemplated by the Merger Agreement, including the Merger. It is possible that additional claims beyond those that have already been filed will be brought by the current plaintiffs or by others in an effort to enjoin the Merger or seek monetary relief from the Partnership. We are not able to predict the outcome of these actions, or others, nor can we predict the amount of time and expense that will be required to resolve the actions. An unfavorable resolution of any such litigation surrounding the proposed Merger could delay or prevent the consummation of the Merger. In addition, the cost to the Partnership of defending the actions, even if resolved in our favor, could be substantial. Such actions could also divert the attention of our management and resources from day-to-day operations.

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Failure to complete the Merger could negatively impact the market price of our common units.

Failure to complete the Merger may negatively impact the future trading price of our common units. If the Merger is not completed, the market price of our common units may decline to the extent that the current market price of our common units reflects a market assumption that the Merger will be completed. Additionally, if the Merger is not completed, we will have incurred significant costs, as well as the diversion of the time and attention of management. A failure to complete the Merger may also result in negative publicity, litigation against the Partnership or our directors and officers, and a negative impression of the Partnership in the investment community. The occurrence of any of these events individually or in combination could have a material adverse effect on our results of operations, financial condition, cash flows, and our unit price.

The Merger is subject to conditions, including certain conditions that may not be satisfied on a timely basis, if at all. Failure to complete the Merger, or significant delays in completing the Merger, could negatively affect the trading prices of AMID Common Units and our Common Units and our future business and financial results of AMID and SXE.

The completion of the Merger is subject to a number of conditions. The completion of the Merger is not assured and is subject to risks, including the risk that approval of the Merger by our unitholders or by governmental agencies is not obtained or that other closing conditions are not satisfied. If the Merger is not completed, or if there are significant delays in completing the Merger, the trading prices of AMID common units and our common units and the respective future business and financial results of AMID and us could be negatively affected, and each of them will be subject to several risks, including the following:

• the parties may be liable for damages to one another under the terms and conditions of the Merger Agreement;

•negative reactions from the financial markets, including declines in the price of AMID common units or our common units due to the fact that current prices may reflect a market assumption that the Merger will be completed;

•and the attention of AMID’s and our management will have been diverted to the Merger rather than each organization’s own operations and pursuit of other opportunities that could have been beneficial to that organization.

The Merger will not occur if the conditions to closing the Contribution under the Contribution Agreement, including AMID refinancing our indebtedness, are not satisfied and the closing of the Contribution does not occur or if the Contribution Agreement is otherwise terminated.

It is a condition to the closing of the Merger under the terms of the Merger Agreement that the Contribution will have closed in accordance with the Contribution Agreement. Additionally, the Merger Agreement will terminate automatically, and the Merger will not occur, if the Contribution Agreement is terminated. The completion of the Contribution is subject to a number of conditions, is not assured and is subject to risks, including the risk that approval by governmental agencies is not obtained or that other closing conditions are not satisfied. Additionally, Holdings may not be able to force AMID to complete the Contribution if AMID has not obtained sufficient financing to make the cash payments required to be made at the closing of the Contribution, including for the refinancing of our indebtedness, in which case AMID may be required under certain circumstances to pay a reverse termination fee of $17 million to Holdings. AMID does not have in place committed financing sufficient to make the payments at the closing of the Contribution, and there can be no assurances that AMID will be able to obtain such financing on acceptable terms or at all. Any such failure to obtain financing would likely result in the termination of the Contribution Agreement and Merger Agreement and the failure to complete the Merger.


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.

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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

In connection with the Merger, as of February 23, 2018, five putative class actions have been filed in the United States District Court for the Northern District of Texas. The actions were filed against multiple, different entities and individuals, including by way of example only and among others, the Partnership, our General Partner, Southcross Holdings, Holdings GP, AMID, AMID Merger Sub, and certain former and current members of our executive management and the Board of Directors of our General Partner.

The complaints generally allege, among other things, that the registration statement on Form S-4 (file no. 333-222501) is false and materially misleading and that the defendants have violated Sections 14(a) and 20(a) of the Securities Exchange Act of 1934 and Rule 14a-9 promulgated thereunder. Generally, the complaints seek class certification, injunctive relief, damages, declaratory relief, and attorney’s fees and court costs.

The five actions filed in the United States District Court for the Northern District of Texas are captioned as follows:


•	Robinson Iglesias v. Southcross Energy Partners, L.P., Southcross Energy Partners GP, LLC, Southcross Holdings LP, Southcross Holdings GP LLC, Bruce A. Williamson, David W. Biegler, Andrew A. Cameron, Nicholas J. Caruso, Jason H. Downie, Wallace Henderson, Jerry W. Pinkerton, Cherokee Merger Sub LLC, and American Midstream Partners, LP, Civil Action No. 3:18-cv-00158-N.


•	Anthony Franchi v. Southcross Energy Partners, L.P., Southcross Energy Partners GP, LLC, Bruce A. Williamson, David W. Biegler, Andrew A. Cameron, Nicholas J. Caruso, Jr., Jason H. Downie, Jerry W. Pinkerton, Randall S. Wade, American Midstream Partners, LP, American Midstream Partners GP, LLC, and Cherokee Merger Sub LLC, Civil Action No. 3:18-cv-00179-D.


•	Adrian Marshall v. Southcross Energy Partners, L.P., Southcross Energy Partners GP, LLC, Southcross Holdings LP, Southcross Holdings GP LLC, Bruce A. Williamson, David W. Biegler, Andrew A. Cameron, Nicholas J. Caruso, Jr., Jason H. Downie, Jerry W. Pinkerton, Randall S. Wade, Bret M. Allan, AmericanMidstream Partners, LP, and Cherokee Merger Sub LLC, Civil Action No. 3:18-cv-00272-D.


•	Kristin Doller v. Southcross Energy Partners, L.P., Southcross Energy Partners GP, LLC, Southcross Holdings LP, Southcross Holdings GP LLC, David W. Biegler, Andrew A. Cameron, Nicholas J. Caruso, Jr., Jason H. Downie, Jerry W. Pinkerton, Randall S. Wade, and Bruce A. Williamson, Civil Action No. 3:18-cv-00291-N.


•	Robert Johnson v. Southcross Energy Partners, L.P., Southcross Energy Partners GP, LLC, Southcross Holdings LP, Southcross Holdings GP LLC, Bruce A. Williamson, David W. Biegler, Andrew A. Cameron, Nicholas J. Caruso, Jr., Jason H. Downie, Jerry W. Pinkerton, Randall S. Wade, Civil Action No. 3:18-cv-00289-C

Please refer to Note 7 of our consolidated financial statements included in this Form 10-K for a description of our legal proceedings.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II


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

Market Information

Our common units are listed on the NYSE 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, 2015. The last reported sale price of our common units on the NYSE on February 23, 2018 was $1.77. Distributions are recorded when paid.



	Unit Prices				Distributions per common unit
Period	High		Low		Distributions per common unit	Payment date
Fourth Quarter 2017	$	2.45	$	1.50	(a)	(a)
Third Quarter 2017	3.19		2.02		(a)	(a)
Second Quarter 2017	4.74		2.50		(a)	(a)
First Quarter 2017	3.70		1.20		(a)	(a)
Fourth Quarter 2016	1.65		1.10		(a)	(a)
Third Quarter 2016	2.10		1.32		(a)	(a)
Second Quarter 2016	3.65		1.02		(a)	(a)
First Quarter 2016	3.73		0.38		(a)	(a)

(a) We did not pay quarterly distributions with respect to these quarters.

As of February 23, 2018, there were 3 holders of record, approximately 5,250 beneficial owners of our common units and 48,623,615 common units outstanding. As of February 23, 2018, we have issued 12,213,713 subordinated units, 18,656,071 Class B Convertible Units and 1,622,314 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,

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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 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. More importantly, the First Amendment and the Fifth Amendment (defined in Note 6 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

General Partner Interest and Incentive Distribution Rights

Our General Partner currently is 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	%

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.”

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Item 6.	Selected Financial Data

As a smaller reporting company, we are not required to provide the information required by Item 6.


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. Our common units are listed on the New York Stock Exchange under the symbol "SXE." We are a master limited partnership, headquartered in Dallas, Texas, that provides natural gas gathering, processing, treating, compression and transportation services and access to 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 two gas processing plants, one fractionation facility and gathering and transportation pipelines.

Recent Developments

The AMID Transactions

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to breaches of representations and warranties regarding the Partnership and our subsidiaries. In addition, Holdings is indemnifying AMID for certain contingent liabilities of the Partnership and our subsidiaries, including several ongoing litigation matters. A portion of the consideration, including approximately $25 million of the AMID Common Units to be received by Holdings will be deposited into escrow in order to secure the potential indemnification obligations until the longer of the end of 12 months from the closing of the Contribution Agreement, May 31, 2019 or the final resolution of the Special Indemnity Matters (as defined in the Contribution Agreement). In addition, all of the AMID Common Units, AMID Preferred Units and the Options received by Holdings as consideration under the Contribution Agreement will be subject to a lock-up agreement whereby such securities will be locked up until the longer of 12 months (with respect to the AMID Common Units) and 24 months (with respect to the AMID Preferred Units and Options) and, together with the AMID GP equity interests, the final resolutions of the Special Indemnity Matters (as defined in the Contribution Agreement). Further, during this time, cash distributions made by AMID or AMID GP to Holdings will be restricted, must remain within Holdings, and will be subject to recapture by AMID. The closing under the Contribution Agreement is conditioned upon, among other things: (i) expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the”HSR Act”), (ii) the absence of certain legal impediments prohibiting the transactions and (iii) with respect to AMID’s obligation to close only, the conditions precedent contained in the Merger Agreement having been satisfied and the Merger having become effective substantially concurrently with the closing of the Contribution Agreement.

The Contribution Agreement contains provisions granting both parties the right to terminate the Contribution Agreement for certain reasons. The Contribution Agreement further provides that, upon termination by Holdings of the Contribution Agreement in the event of a Funding Failure (as defined in the Contribution Agreement), AMID may be required to pay a reverse termination fee in an amount up to $17 million.

Amendments to Third A&R Revolving Credit Agreement

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N.A., UBS Securities LLC, Barclays Bank PLC and a syndicate of lenders (the "Third A&R Revolving Credit Agreement"), as amended in May 2015, due to an administrative oversight, which resulted in a default. On July 26, 2016, Holdings fully funded the first quarter 2016 equity cure. On August 4, 2016, we entered into a limited waiver and second amendment to the Third A&R Revolving Credit Agreement whereby the lenders waived any default or right to exercise any remedy as a result of this technical event of default to fund timely the first quarter 2016 equity cure.

On November 8, 2016, we entered into a limited waiver and third amendment to the Third A&R Revolving Credit Agreement (the “Third Amendment”), which stipulated, among other things, that (i) the equity cure funding deadline for the quarter ended September 30, 2016 (“Q3 2016 Equity Cure”) was extended from November 23, 2016 to December 16, 2016, and (ii) limited the total revolving credit exposure. On December 9, 2016, we entered into the waiver and fourth amendment to the Third A&R Revolving Credit Agreement (the "Fourth Amendment"), which stipulated, among other things, that (i) the deadline for funding the Q3 2016 Equity Cure was further extended from December 16, 2016 to January 12, 2017, and (ii) the Third A&R Revolving Credit Agreement was amended to require that any account into which we deposit funds, securities or commodities be subject to a lien and a control agreement for the benefit of the secured parties under the Third A&R Revolving Credit Agreement.

On December 29, 2016, we entered into the fifth amendment (the "Fifth Amendment") to the Third Amended and Restated Revolving Credit Agreement with Wells Fargo, N.A., UBS Securities LLC, Barclays Bank PLC and a syndicate of lenders (the "Third A&R Revolving Credit Agreement"), pursuant to which we received a full waiver for all defaults or events of default arising out of our failure to comply with the financial covenant to maintain a Consolidated Total Leverage Ratio (as defined in the Fifth Amendment) less than 5.00 to 1.00 for the quarter ended September 30, 2016.

Additionally, pursuant to the Fifth Amendment, (i) total aggregate commitments under the Third A&R Revolving Credit Agreement were reduced from $200 million to $135 million (then further reduced to $125 million on March 31, 2018) and the sublimit for letters of credit also was reduced from $75 million to $50 million (total aggregate commitments will be periodically further reduced through December 31, 2018); (ii) the Consolidated Total Leverage Ratio and Consolidated Senior Secured Leverage Ratio (each as defined in the Fifth Amendment) financial covenants were suspended until the quarter ended March 31, 2019; and (iii) the Consolidated Interest Coverage Ratio (as defined in the Fifth Amendment) financial covenant requirement was reduced from 2.50 to 1.00 to 1.50 to 1.00 for all periods ending on or prior to December 31, 2018 (the “Ratio Compliance Date”). Prior to the Ratio Compliance Date, we will be required to maintain minimum levels of Consolidated EBITDA (as defined in the Fifth Amendment) on a quarterly basis and are subject to certain covenants and restrictions related to liquidity and capital expenditures. See Note 6 to our consolidated financial statements.

In connection with the execution of the Fifth Amendment, on December 29, 2016, the Partnership entered into (i) an Investment Agreement (the “Investment Agreement”) with Holdings and Wells Fargo Bank, N.A., (ii) a Backstop Agreement (the “Backstop Agreement”) with Holdings, Wells Fargo Bank, N.A. and the Sponsors and (iii) a First Amendment to the Equity Cure Contribution Agreement (the “Equity Cure Contribution Amendment”) with Holdings. Pursuant to the Equity Cure Contribution Amendment, on December 29, 2016, Holdings contributed $17.0 million to us in exchange for 11,486,486 common units. The proceeds of the $17.0 million contribution were used to pay down the outstanding balance under the Third A&R Revolving Credit Agreement and for general corporate purposes. In addition, on January 2, 2018, we notified Holdings that a Full Investment Trigger (as defined in the Investment Agreement) occurred on December 31, 2017. Pursuant to the Backstop Agreement, on January 2, 2018, Holdings delivered a Backstop Demand (as defined in the Investment Agreement) for each Sponsor to fund their respective pro rata portions of the Sponsor Shortfall Amount (as defined in the Investment Agreement) of $15.0 million in accordance with the Backstop Agreement. As consideration for the amount provided directly to us by a Sponsor pursuant to the Backstop Agreement, we issued to the Sponsors senior unsecured notes of the Partnership in an aggregate principal amount of $15.0 million (each, an "Investment Note" and collectively, the “Investment Notes”). The Investment Notes mature on November 5, 2019 and bear interest at a rate of 12.5% per annum. Interest on the Investment Note shall be paid in kind (other than with respect to interest payable (i) on or after the maturity date, (ii) in connection with prepayment, or (iii) upon acceleration of the Investment Note, which shall be payable in cash); provided that all interest shall be payable in cash on or after December 31, 2018. The Investment Notes are the unsecured obligation of the Partnership subordinate in right of payment to any of our secured obligations under the Third A&R Revolving Credit Agreement.

Holdings Chapter 11 Reorganization

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contributed $85 million in cash (or $170 million in the aggregate) in exchange for each Sponsor receiving 33.33% of the limited partner interests in Holdings. In addition, Holdings committed to provide us $50 million (the "Contribution Amount") (as part of the Equity Cure Agreement defined below), out of the $170 million in new equity contributed to Holdings from the Sponsors, to provide us with liquidity to comply with the applicable financial covenants set forth in our credit agreement at the time.

Distribution Suspension

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 energy production, primarily from crude oil and natural gas. 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.

Total U.S. natural gas consumption averaged 74.0 billion cubic feet per day (Bcf/d) in 2017, a 1% decrease from 2016. Natural gas consumption is forecast to increase by 3.5 Bcf/d in 2018 and by 2.2 Bcf/d in 2019. The 2017 decrease in total natural gas consumption mainly reflects warm winter temperatures and lower electric power sector use. In 2017, U.S. heating degree days (HDD) were 2% lower than in 2016, and U.S. cooling degree days (CDD) in 2017 were 8% lower than in 2016. Electric power sector use of natural gas decreased by 1.6 Bcf/d (6%) in 2017. The decline reflects competition from increasing renewable energy use (particularly hydropower), competitive coal prices, and overall lower electricity generation levels.

The EIA estimates that dry natural gas production averaged 73.6 Bcf/d in 2017, a increase of 1.2 Bcf/d (1.7%) from 2016. The strongest growth in dry natural gas production occurred late in the year, as improved economics related to expanded pipeline capacity contributed to a 3.8% increase in production between the third and fourth quarters of 2017. The rate of production growth is expected to moderate in 2018.

Natural gas pipeline exports increased by 0.4 Bcf/d (6.8%) to 6.3 Bcf/d in 2017, and the EIA expects growth to continue over the forecast period with ongoing Mexican energy market reform. A relatively low natural gas export price, rising demand from Mexico’s power sector, and increased pipeline capacity in both in the United States and Mexico have led to increased exports. U.S. gross pipeline exports are expected to increase by 0.6 Bcf/d in 2018 and by 0.8 Bcf/d in 2019 to an average of 8.0 Bcf/d.

The EIA projects liquefied natural gas (LNG) gross exports will average 3.0 Bcf/d in 2018, up from 1.9 Bcf/d in 2017. In 2018, U.S. liquefaction capacity will continue to expand. The EIA expects the Cove Point terminal in Maryland to ramp up to full capacity. At the Elba Island facility in Georgia, 6 of the 10 small modular trains, each with a capacity of 0.03 Bcf/d, are expected to enter service. The first liquefaction train (capacity 0.7 Bcf/d) at Freeport LNG in Texas is also expected to come online by the end of 2018. The EIA projects gross LNG exports to average 4.8 Bcf/d in 2019, when the four remaining modular trains at Elba Island come online and the remaining two trains at Freeport LNG enter service. Two trains in Corpus Christi, Texas, and three trains at Cameron LNG in Louisiana are also expected to enter service in 2019. EIA forecasts exports will

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ramp up in the second half of 2019 to an average of 5.5 Bcf/d, up from 4.1 Bcf/d in the first half of 2019. In both 2018 and 2019 the new liquefaction facilities will require a ramp up period, and they are forecast to operate below nameplate capacity for a period of time, lowering the overall LNG export capacity utilization rate.

The total U.S. natural gas imports averaged 8.2 Bcf/d in 2017, and they are expected to average 7.9 Bcf/d in 2018 and 8.2 Bcf/d in 2019. A low natural gas price environment in Western Canada could contribute to increased seasonal imports for some regional U.S. markets.

In 2017, the United States was a net exporter of natural gas for the first time on an annual basis, with net exports averaging 0.4 Bcf/d. Overall, net natural gas exports are forecast to average 2.3 Bcf/d in 2018 and 4.6 Bcf/d in 2019.

Interest Rate Environment

In 2017, interest rates were increased by the Federal Reserve three times, which marks the fifth increase since June 2016, signaling that rates may continue to rise in 2018. The Federal Reserve expects that economic conditions will continue to evolve in a manner that will warrant gradual increases in interest rates three times again in 2018. 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 plant, the commercial terms of our contractual arrangements, natural gas and NGL prices and our operations and maintenance expense. We manage our business with the goal to maximize the gross operating margin we earn from contracts balanced against any risks we assume in our contracts. Our contracts vary in duration from one month to several years and the pricing under our contracts varies depending upon several factors, including our competitive position, our acceptance of risks associated with longer-term contracts and our desire to recoup over the term of the contract any capital expenditures that we are required to incur to provide service to our customers. We purchase, gather, process, treat, compress, transport and sell natural gas and purchase, fractionate, transport and sell NGLs. Contracts with a counterparty generally contain one or more of the following arrangements:


•	Fixed-Fee. We receive a fixed-fee per unit of natural gas volume that we gather at the wellhead, process, treat, compress and/or transport for our customers, or we receive a fixed-fee per unit of NGL volume that we fractionate. Some of our arrangements also provide for a fixed-fee for guaranteed transportation capacity on our systems.

•

Fixed-Spread. Under these arrangements, we purchase natural gas and NGLs from producers or suppliers at receipt points on our systems at an index price plus or minus a fixed price differential and sell these volumes of natural gas and NGLs at delivery points off our systems at the same index price, plus or minus a fixed price differential. By entering into such back-to-back purchases and sales, we are able to mitigate our risk associated with changes in the general commodity price levels of natural gas and NGLs. We remain subject to variations in our fixed-spreads to the extent we are unable to precisely match volumes purchased and sold in a given time period or are unable to secure the supply or to produce or market the necessary volume of products at our anticipated differentials to the index price.

•

Commodity-Sensitive. In exchange for our processing services, we may remit to a customer a percentage of the proceeds from our sales, or a percentage of the physical volume, 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 generally are 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.

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We assess gross operating margin opportunities across our integrated value stream so that processing margins may be supplemented by gathering and transportation fees and opportunities to sell residue gas and NGLs at fixed-spreads. Gross operating margin earned under fixed-fee and fixed-spread arrangements is related directly 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. For our gathering, transportation and other services agreements with Holdings (see Note 8 to our consolidated financial statements), fee based revenue increases with no associated cost of natural gas and liquids sold. We enter into primarily fixed-fee and fixed-spread deals.

How We Evaluate Our Operations

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

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 liquidity 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, severance expense 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 a key metric used in measuring our compliance with our financial covenants under our debt agreements and 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 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, income tax expense and maintenance capital expenditures. We use distributable cash flow to analyze our 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.

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Non-GAAP Financial Measures

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 and net cash provided by operating activities are

the GAAP measures most directly comparable to 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 Adjusted EBITDA or distributable cash flow in

isolation or as a substitute for analysis of our results as reported under GAAP. Because 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 across industry lines.

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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,
	2017			2016

Net cash provided by operating activities	$	26,182		$	50,642
Add (deduct):
Depreciation and amortization	(71,902		)	(106,947		)
Unit-based compensation	(1,375		)	(3,523		)
Amortization of deferred financing costs and original issuance discount	(3,569		)	(3,354		)
Gain on sale of assets, net	5			11,768
Unrealized gain (loss) on financial instruments	(2		)	147
Equity in losses of joint venture investments	(13,060		)	(21,123		)
Impairment of assets	(1,769		)	(476		)
Distribution from joint venture investment	—			(740		)
Gain on insurance proceeds	1,508			—
Gain on legal settlements	—			2,375
Write-off of deferred financing costs	—			(1,006		)
Other, net	474			310
Changes in operating assets and liabilities:
Trade accounts receivable, including affiliates	5,425			(31,554		)
Prepaid expenses and other current assets	(829		)	(947		)
Other non-current assets	58			358
Accounts payable and accrued liabilities, including affiliates	(9,257		)	18,234
Other liabilities	519			(9,112		)
Net loss	$	(67,592	)	$	(94,948	)
Add (deduct):
Depreciation and amortization	$	71,902		$	106,947
Interest expense	38,181			35,166
Revenue deferral adjustment	3,016			3,016
Unit-based compensation	1,375			3,523
Income tax (benefit) expense	4			(2		)
Gain on sale of assets, net	(5		)	(11,768		)
Major litigation costs, net of recoveries	311			495
Equity in losses of joint venture investments	13,060			21,123
Severance expense	2,955			472
Retention bonus funded by Holdings	91			3,168
Valley Wells' operating expense cap adjustment	—			2,406
Fees related to Equity Cure Agreement	—			650
Distribution from joint venture investment	—			740
Transaction-related costs	3,752			6
Impairment of assets	1,769			476
Gain on insurance proceeds	(1,508		)	—
Gain on legal settlements	—			(3,939		)
Write-off of deferred financing costs	—			1,006
Expenses related to shut-down of Conroe processing plant and conversion of Gregory processing plant	1,568			—
Other, net	301			990
Adjusted EBITDA	$	69,180		$	69,527
Cash paid for interest	(35,142		)	(32,459		)
Income tax benefit (expense)	(4		)	2
Maintenance capital expenditures	(4,789		)	(4,711		)
Distributable cash flow	$	29,245		$	32,359

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QUARTERLY FINANCIAL INFORMATION

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



	Quarters ended
	March 31			June 30			September 30			December 31

Net cash provided by (used in) operating activities	$	202		$	11,094		$	14,552		$	334
Add (deduct):
Depreciation and amortization	(17,850		)	(18,302		)	(17,521		)	(18,229		)
Unit-based compensation	(257		)	(157		)	(827		)	(134		)
Amortization of deferred financing costs and original issuance discount	(951		)	(879		)	(889		)	(850		)
Gain (loss) on sale of assets, net	62			129			(186		)	—
Unrealized gain (loss) on financial instruments	2			2			(4		)	(2		)
Equity in losses of joint venture investments	(3,316		)	(3,331		)	(3,218		)	(3,195		)
Impairment of assets	(649		)	—			(1,120		)	—
Gain on legal settlements	1,508			—			—			—
Other, net	285			63			63			63
Changes in operating assets and liabilities:
Trade accounts receivable, including affiliates	(11,257		)	10,619			(11,865		)	17,928
Prepaid expenses and other current assets	630			(2,089		)	1,431			(801		)
Other non-current assets	(61		)	(4		)	87			36
Accounts payable and accrued expenses, including affiliates	12,099			(11,415		)	1,228			(11,169		)
Other liabilities	4,170			(1,600		)	(789		)	(1,262		)
Net loss	$	(15,383	)	$	(15,870	)	$	(19,058	)	$	(17,281	)
Add (deduct):
Depreciation and amortization	$	17,850		$	18,302		$	17,521		$	18,229
Interest expense	9,103			9,636			9,931			9,511
Income tax expense	—			2			2			—
Loss (gain) on sale of assets, net	(62		)	(129		)	186			—
Revenue deferral adjustment	754			754			754			754
Unit-based compensation	257			157			827			134
Major litigation costs, net of recoveries	33			116			95			67
Transaction-related costs	—			—			1,387			2,365
Equity in losses of joint venture investments	3,316			3,331			3,218			3,195
Severance expense	2,334			414			63			144
Retention bonus funded by Holdings	—			—			91			—
Impairment of assets	649			—			1,120			—
Gain on insurance proceeds	(1,508		)	—			—			—
Expenses related to shut-down of Conroe processing plant and conversion of Gregory processing plant	294			313			681			280
Other, net	381			44			(55		)	(69		)
Adjusted EBITDA	$	18,018		$	17,070		$	16,763		$	17,329

Key Factors Affecting Operating Results and Financial Condition

•

Impact of Hurricane Harvey. We began preparing our South Texas Gulf Coast assets for the impact of Hurricane Harvey prior to the storm’s landfall in late August 2017 to maintain the safety of our facilities, our neighbors and our employees. Fortunately, our Gulf Coast assets sustained only minor wind and flood damage as a result of the storm. These facilities resumed operation within a few days after third party electrical power was restored to them. Our South Texas assets located further inland were temporarily shut-down because our downstream sales markets for both natural gas and NGLs were closed for a short period of time. Over 90% of our South Texas gas supply and downstream sales markets resumed normal operations by early September 2017, and full pre-storm operations were achieved by the end of September 2017. Our Mississippi and Alabama assets were not impacted by Hurricane Harvey. Excluding the impact of Hurricane Harvey, processed gas volumes would have been 270 MMcf/d during the year ended December 31, 2017.

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•

Holdings' Lancaster Gas Treating Facility Fire. In February 2016, due to a fire, there was an outage at our Lancaster gas treating facility through April 2016. The outage at the Lancaster gas treating facility caused processed gas volumes and NGL production to decrease for the year ended December 31, 2016. In 2017, we received $1.1 million in business interruption proceeds as a result of the outage.

Results of Operations

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



	Year Ended December 31,
	2017			2016
Revenues:
Revenues	$	470,237		$	451,271
Revenues - affiliates	195,712			97,452
Total revenues	665,949			548,723
Expenses:
Cost of natural gas and liquids sold	524,675			395,874
Operations and maintenance	59,217			70,242
Depreciation and amortization	71,902			106,947
General and administrative	26,246			28,546
Impairment of assets	1,769			476
Gain on sale of assets, net	(5		)	(11,768		)
Total expenses	683,804			590,317
Loss from operations	(17,855		)	(41,594		)
Other income (expense):
Equity in losses of joint venture investments	(13,060		)	(21,123		)
Interest expense	(38,181		)	(35,166		)
Gain on insurance proceeds	1,508			—
Write-off of deferred financing costs	—			(1,006		)
Gain on legal settlements	—			3,939
Total other expense	(49,733		)	(53,356		)
Loss before income tax benefit (expense)	(67,588		)	(94,950		)
Income tax benefit (expense)	(4		)	2
Net loss	$	(67,592	)	$	(94,948	)

Other financial data:
Adjusted EBITDA	$	69,180		$	69,527

Maintenance capital expenditures	$	4,789		$	4,711
Growth capital expenditures	$	18,001		$	22,562

Operating data:
Average volume of processed gas (MMcf/d)	250			312
Average volume of NGLs produced (Bbls/d)	30,824			32,271
Average daily throughput Mississippi/Alabama (MMcf/d)	166			160

Realized prices on natural gas volumes ($/Mcf)	$	3.17		$	2.34
Realized prices on NGL volumes ($/gal)	0.52			0.34

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2017 Compared with 2016

Volume and overview. Processed gas volumes decreased 62 MMcf/d, or 20%, to 250 MMcf/d during the year ended December 31, 2017, compared to 312 MMcf/d during the year ended December 31, 2016. The decrease in processed gas volumes is due primarily to the shut-down of the Conroe facility in the fourth quarter of 2016, lower volumes from producers in our dry-gas areas of South Texas and the temporary shut-down of our processing plants as a result of Hurricane Harvey during the third quarter of 2017. The decrease is offset partially by higher volumes from producers in our rich-gas areas of South Texas, including Karnes, Frio and LaSalle counties.

NGLs produced at our processing plants for the year ended December 31, 2017 averaged 30,824 Bbls/d, a decrease of 4%, or 1,447 Bbls/d, compared to 32,271 Bbls/d for the year ended December 31, 2016. The decrease in NGLs produced is due primarily to a decline in processed gas volumes offset partially by higher ethane recoveries at our processing plants.

Revenue. Our total revenues for 2017 increased $117.2 million, or 21%, to $665.9 million compared to $548.7 million in 2016. This increase was due primarily to an increase in realized prices in natural gas and NGLs, offset partially by a reduction in processed gas volumes. Revenue from the sales of natural gas for the year ended December 31, 2017 increased $108.1 million, or 40%, to $379.4 million compared to $271.3 million for the year ended December 31, 2016. Revenue from the sales of NGLs and condensate for the year ended December 31, 2017 increased $20.2 million, or 13%, to $179.2 million compared to $159.0 million for the year ended December 31, 2016.

Cost of natural gas and NGLs sold. Our cost of natural gas and NGLs sold for the year ended December 31, 2017 was $524.7 million, compared to $395.9 million for the year ended December 31, 2016. This increase of $128.8 million, or 33%, was due primarily to higher natural gas and NGL prices as compared to the same period in 2016.

Operations and maintenance expenses. Operations and maintenance expenses for the year ended December 31, 2017 were $59.2 million, compared to $70.2 million for the year ended December 31, 2016 for a decrease of $11.0 million, or 16%. This decrease was due primarily to idling of the Bonnie View fractionation facility, shutting down the Conroe facility, converting the Gregory facility to a compressor station and improved operating efficiencies at our facilities, including our decision to reduce the utilization of the T2 Cogen facility.

General and administrative expenses. General and administrative expenses for the year ended December 31, 2017 were $26.2 million, compared to $28.5 million for the year ended December 31, 2016. This decrease of $2.3 million, or 8%, is due primarily to cost-saving initiatives of $5.6 million, including lower employee, office related and professional service expenses offset partially by transaction-related expenses of $3.5 million.

Depreciation and amortization expense. Depreciation and amortization expense for the year ended December 31, 2017 was $71.9 million, compared to $106.9 million for the year ended December 31, 2016. The decrease of $35.0 million, or 33%, was due primarily to accelerating the depreciation of our Conroe and Gregory facilities beginning August 2016 in response to management’s plans to shut down the Conroe facility and convert the Gregory facility to a compressor station during the fourth quarter of 2016.

Equity in losses of joint venture investments. Our share of losses incurred by our joint venture investments was $13.1 million for the year ended December 31, 2017 and $21.1 million for the year ended December 31, 2016. 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. This decrease of $8.0 million, or 38%, was due primarily to a $13.3 million impairment of the T2 Cogen Facility during the fourth quarter of 2016.

Interest expense. For the year ended December 31, 2017, interest expense was $38.2 million, compared to $35.2 million for the year ended December 31, 2016. This increase of $3.0 million, or 9%, was due primarily to higher interest rates on borrowings.

Liquidity and Capital Resources

Sources of Liquidity

Our primary sources of liquidity are cash generated from operations, cash raised through issuances of additional debt securities and borrowings under our Senior Credit Facilities (as defined in Note 6 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 and purchases and construction of new assets.

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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 through several sources, including operating cash flows and borrowings under our Senior Credit Facilities. See Notes 2 and 6 to our consolidated financial statements.

Our future cash flow will be materially adversely affected if the prices for natural gas, NGL and crude oil continue to affect the drilling for oil or natural gas in our primary operating area, the Eagle Ford Shale. See Notes 1 and 2 to our consolidated financial statements. The majority of our revenue is derived from fixed-fee and fixed-spread contracts, which have limited direct exposure to commodity price levels since we are paid based on the volumes of natural gas that we gather, process, treat, compress and transport and the volumes of NGLs we fractionate and transport, rather than being paid based on the value of the underlying natural gas or NGLs. In addition, a portion of our contract portfolio contains minimum volume commitment arrangements. The majority of our volumes are dependent upon the level of producer drilling activity. We remain focused on our efforts to improve future liquidity, and have implemented cost-saving initiatives in 2016 and 2017 to lower our operating and general and administrative cost structure. Additionally, we have explored various strategic options resulting in the Merger Agreement and Contribution Agreement.

On December 29, 2016, we entered into the Fifth Amendment, pursuant to which we received a full waiver for all defaults or events of default arising out of our failure to comply with the financial covenant to maintain a Consolidated Total Leverage Ratio less than 5.00 to 1.00 for the quarter ended September 30, 2016. In addition, until such time as our Consolidated Total Leverage Ratio is less than or equal to 5.00 to 1.00, we will be required to repay any outstanding borrowings under the Credit Facility in an amount equal to 50% of our Excess Cash Flow (as defined in the Fifth Amendment). As of December 31, 2017, our Consolidated Total Leverage Ratio was 8.14 to 1.00

Additionally, pursuant to the Fifth Amendment, (i) the total aggregate commitments under the Third A&R Revolving Credit Agreement were reduced from $200 million to $135 million (then further reduced to $125 million on March 31, 2018) and the sublimit for letters of credit was also reduced from $75 million to $50 million (total aggregate commitments will be periodically reduced further through December 31, 2018); (ii) the Consolidated Total Leverage Ratio and Consolidated Senior Secured Leverage Ratio (each of which is defined in the Fifth Amendment) financial covenants were suspended until the quarter ended March 31, 2019; and (iii) the Consolidated Interest Coverage Ratio (as defined in the Fifth Amendment) financial covenant requirement was reduced from 2.50 to 1.00 to 1.50 to 1.00 for all periods ending on or prior to December 31, 2018. Prior to the Ratio Compliance Date, we will be required to maintain minimum levels of Consolidated EBITDA on a quarterly basis and be subject to certain covenants and restrictions related to liquidity and capital expenditures. See Notes 2 and 6 to our consolidated financial statements.

On January 22, 2018, in connection with the Investment Agreement and the Backstop Agreement, the Sponsors provided us $15.0 million in exchange for the Investment Notes. See Note 2 to the consolidated financial statements.

As of February 23, 2018, we had $538.0 million in outstanding borrowings under our Senior Credit Facilities (as defined in Note 6 to our consolidated financial statements) and $15.0 million in Investment Notes (inclusive of PIK interest). We currently have the ability to borrow up to $135.0 million less any letters of credit amounts outstanding. As of February 23, 2018, under our five-year revolving credit facility (the "Credit Facility"), pursuant to our Third A&R Revolving Credit Agreement, we had $538.0 million in outstanding borrowings under our Senior Credit Facilities (as defined in Note 6 to our consolidated financial statements), letters of credit of $25.1 million, which as of February 23, 2018 provided us access to $25.4 million.

Capital expenditures. Our business is capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of and will continue to include:


•	growth capital expenditures, which are capital expenditures to expand or increase the efficiency of the existing operating capacity of our assets. Growth capital expenditures include expenditures that facilitate an increase in volumes within our operations, but exclude expenditures for acquisitions; and


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

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The following table summarizes our capital expenditures (in thousands):



	Year Ended December 31,
	2017		2016
Maintenance capital	$	4,789	$	4,711
Growth capital	18,001		22,562
Total capital expenditures	$	22,790	$	27,273

Our growth capital expenditures during the year ended December 31, 2017 primarily related to the installation of a new gas gathering pipeline in Mississippi of $3.9 million, the installation of a new upgraded amine system at our Woodsboro processing facility of $3.0 million, and various projects to connect new production or sales to our assets of $4.6 million, of which the majority were aid-in-construction projects whereby the producer reimbursed us for the cost of connecting the gas supply. Our growth capital expenditures during the year ended December 31, 2016 primarily relate to various expansion and improvement projects primarily in our South Texas assets.

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

Our ability to benefit from growth projects to accommodate producer drilling activity and the associated need for

infrastructure assets and services is subject to operational risks and uncertainties such as the uncertainty inherent in some of the

assumptions underlying design specifications for new, modified or expanded facilities. These risks also impact third party

service providers and their facilities. Delays or under-performance of our facilities or third party facilities may adversely affect

our ability to generate cash from operations and comply with our obligations, including the covenants under our debt

instruments. In other cases, actual production delivered may fall below volume estimates that we relied upon in deciding to

pursue an acquisition or other growth project. Future cash flow and our ability to comply with our debt covenants would

likewise be affected adversely if we continue to experience declining volumes over a sustained period and/or unfavorable

commodity prices.

We believe that cash from operations, cash on hand and the Committed Amount received from the Sponsors, will provide sufficient liquidity to meet future short-term capital requirements through at least twelve months from the date that the financial statements included in this Form 10-K are issued. However, during management's ongoing assessment of the Partnership's financial forecast, the Holdings GP Board and the SXE GP Board considered that in our corporate structure and absent continued access to equity cures from our Sponsors or a significant equity infusion from a third party, which the Partnership may not be able to obtain, or absent additional amendments to its Revolving Credit Agreement or waivers of the March 31, 2019 requirement to comply with the consolidated total leverage ratio, the Partnership is not expected to be able to comply with such financial covenant as of such date, which would trigger an event of default, and result in substantial doubt regarding SXE’s ability to continue as a going concern as early as the end of the first quarter of 2018. Growth projects are a key element of our business strategy. We intend to finance any required growth capital through several sources, including operating cash flows, borrowings under our Senior Credit Facilities and the issuance of additional debt securities. The timing, size or success of any expansion effort and the associated potential capital commitments are unpredictable. To consummate capital projects, we may require access to additional capital. Our access to capital long-term will depend on our future operating performance, financial condition and credit rating and, more broadly, on the availability of debt financing, which will be affected by prevailing conditions in our industry, the economy and the financial markets and other financial and business factors, many of which are beyond our control.

Cash Flows

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



	Year Ended December 31,
	2017			2016
Net cash provided by operating activities	$	26,182		$	50,642
Net cash used in investing activities	(8,174		)	(8,904		)
Net cash used in financing activities	(34,016		)	(31,860		)

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2017 Compared with 2016

Operating Activities— Net cash provided by operating activities was $26.2 million for the year ended December 31, 2017, compared to $50.6 million for the year ended December 31, 2016. The decrease in cash provided by operating activities of $24.4 million was due primarily to higher settlements of affiliated accounts receivable during the year ended December 31, 2016 compared to the year ended December 31, 2017.

Investing Activities—Net cash used in investing activities was $8.2 million for the year ended December 31, 2017, compared to $8.9 million for the year ended December 31, 2016. The decrease of $0.7 million used in investing activities during the year ended December 31, 2017 was due to lower capital expenditures of $22.8 million, additional payments received from aid in construction payments of $9.9 million, lower investment contributions to joint ventures of $0.7 million, offset partially by lower proceeds from the sales of assets of $3.4 million during the year ended December 31, 2017.

Financing Activities—Net cash used in financing activities for the year ended December 31, 2017 was $34.0 million, compared to $31.9 million for the year ended December 31, 2016. The decrease of $2.1 million was due primarily to $31.1 million of additional net paydowns on our Credit Facility during the year ended December 31, 2016 as compared to the year ended December 31, 2017, offset partially by $29.4 million for equity cures during the year ended December 31, 2016.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Critical Accounting Policies

The accounting policies described below are considered critical to obtaining an understanding of our consolidated financial statements because their application requires significant estimates and judgments by management in preparing our consolidated financial statements. Management's estimates and judgments are inherently uncertain and may differ significantly from actual results achieved. Management considers an accounting estimate to be critical if the following conditions apply:


•	the estimate requires significant assumptions; and


•	changes in the estimate could have a material effect on our consolidated statements of operations or financial condition; or


•	if different estimates that could have been selected had been used, there could be a material effect on our consolidated statements of operations or financial condition.

We have discussed the selection and application of these accounting estimates with the Audit Committee of the board of directors of our general partner and our independent registered public accounting firm. It is management's view that the current assumptions and other considerations used to estimate amounts reflected in our consolidated financial statements are appropriate. However, actual results can differ significantly from those estimates under different assumptions and conditions.

Revenue Recognition

Using the revenue recognition criteria of persuasive evidence that an exchange arrangement exists, delivery has occurred or services have been rendered and the price is fixed or determinable, we record natural gas and NGL revenue in the period when the physical product is delivered to the customer and in an amount based on the pricing terms of an executed contract. Our transportation, compression, processing, fractionation and other revenue is recognized in the period when the service is provided and includes our fee-based service revenue. In addition, collectability is evaluated on a customer-by-customer basis. New customers are subject to a credit review process, which evaluates the customers' financial position and their ability to pay.

Our sale and purchase arrangements primarily are accounted for on a gross basis in the statements of operations. These transactions are contractual arrangements that establish the terms of the purchase of natural gas or NGLs at a specified location and the sale of natural gas or NGLs at a different location on the same or on another specified date. These transactions require physical delivery and transfer of the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk.

Certain of our gas gathering agreements provide for a monthly, quarterly or annual minimum volume commitment ("MVC") from our customers. Under these MVCs, our customers agree to ship and/or process a minimum volume of production on our system or to pay a minimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to us at the end of the contracted measurement period if its actual throughput volumes are less than its MVC for that period. Certain customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent contracted measurement periods to the extent that such customer's throughput volumes in a subsequent contracted measurement period exceed its MVC for that period. We recognize customer billings for obligations under their MVCs as

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revenue when the obligations are billable under the contract and the customer does not have the right to utilize shortfall payments to offset gathering fees in excess of its MVCs in subsequent periods.

Impairment of Long-Lived Assets

We evaluate our long-lived assets by asset group, which include finite-lived intangible assets, for impairment when events or circumstances indicate that the asset group's carrying values may not be recoverable. These events include, but are not limited to, market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset or group, decisions to sell an asset and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, we evaluate the recoverability of our carrying value based on the long-lived asset group's ability to generate future cash flows on an undiscounted basis. If the undiscounted cash flows are not sufficient to recover the long-lived asset group's carrying value, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying values of the asset downward, if necessary, to their estimated fair value. Our fair value estimates are based generally on assumptions market participants would use, including market data obtained through the sales process or an analysis of expected discounted cash flows. During the year ended December 31, 2017, we recorded $1.8 million related to the write-down of assets held for sale at the Gregory processing facility and canceled AFEs. During the year ended December 31, 2016, we recorded a charge of $0.5 million related to the write-off of software costs.

New Accounting Pronouncements

For a complete description of new accounting pronouncements, see Note 1 to our consolidated financial statements.


Item 7A.	Quantitative and Qualitative Disclosures About Market Risk

As a smaller reporting company, we are not required to provide the information required by Item 7A.

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Item 8.	Financial Statements and Supplementary Data

SOUTHCROSS ENERGY PARTNERS, L.P.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



	Page
Report of Independent Registered Public Accounting Firm	69
Consolidated Balance Sheets as of December 31, 2017 and 2016	70
Consolidated Statements of Operations for the Years Ended December 31, 2017 and 2016	71
Consolidated Statements of Cash Flows for the Years Ended December 31, 2017 and 2016	72
Consolidated Statements of Changes in Partners' Capital for the Years Ended December 31, 2017 and 2016	73
Notes to Consolidated Financial Statements	74

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Southcross Energy Partners, L.P. and subsidiaries (the "Partnership") as of December 31, 2017 and 2016, the related consolidated statements of operations, changes in partners’ capital and cash flows, for each of the two years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Emphasis of a Matter

As discussed in Notes 1 and 2 to the consolidated financial statements, on October 31, 2017, the Partnership, its general partner and Southcross Holdings LP entered into an Agreement and Plan of Merger with American Midstream Partners, LP (“AMID”) and its general partner whereby, at closing, the Partnership will be merged with, and become, a wholly owned subsidiary of AMID.

/s/ Deloitte & Touche LLP

Dallas, Texas

March 1, 2018

We have served as the Partnership's auditor since 2010.

SOUTHCROSS ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands, except for unit data)



	December 31, 2017		December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	5,218	$	21,226
Trade accounts receivable	33,920		51,894
Accounts receivable - affiliates	33,163		7,976
Prepaid expenses	2,592		2,751
Other current assets	497		4,343
Total current assets	75,390		88,190

Property, plant and equipment, net	914,547		971,286
Investments in joint ventures	111,747		124,096
Other assets	2,519		2,504
Total assets	$	1,104,203	$	1,186,076

LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	57,782	$	50,639
Accounts payable - affiliates	378		524
Current portion of long-term debt	4,256		4,500
Other current liabilities	12,976		10,976
Total current liabilities	75,392		66,639

Long-term debt	514,266		543,872
Other non-current liabilities	14,979		11,936
Total liabilities	604,637		622,447

Commitments and contingencies (Note 7)

Partners' capital:
Common units (48,614,187 and 48,502,090 units outstanding as of December 31, 2017 and 2016, respectively)	215,146		255,124
Class B Convertible units (18,335,181 and 17,105,875 units issued and outstanding as of December 31, 2017 and 2016, respectively)	266,725		278,508
Subordinated units (12,213,713 units issued and outstanding as of December 31, 2017 and 2016, respectively)	8,302		19,240
General partner interest	9,393		10,757
Total partners' capital	499,566		563,629
Total liabilities and partners' capital	$	1,104,203	$	1,186,076

See accompanying notes to these consolidated financial statements.

SOUTHCROSS ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except for per unit data)



	Year Ended December 31,
	2017			2016
Revenues:
Revenues	$	470,237		$	451,271
Revenues - affiliates	195,712			97,452
Total revenues (Note 11)	665,949			548,723

Expenses:
Cost of natural gas and liquids sold	524,675			395,874
Operations and maintenance	59,217			70,242
Depreciation and amortization	71,902			106,947
General and administrative	26,246			28,546
Impairment of assets	1,769			476
Gain on sale of assets, net	(5		)	(11,768		)
Total expenses	683,804			590,317

Loss from operations	(17,855		)	(41,594		)
Other income (expense):
Equity in losses of joint venture investments	(13,060		)	(21,123		)
Interest expense	(38,181		)	(35,166		)
Gain on insurance proceeds	1,508			—
Write-off of deferred financing costs	—			(1,006		)
Gain on legal settlements	—			3,939
Total other expense	(49,733		)	(53,356		)
Loss before income tax benefit (expense)	(67,588		)	(94,950		)
Income tax benefit (expense)	(4		)	2
Net loss	(67,592		)	(94,948		)
General partner unit in-kind distribution	(65		)	(47		)
Net loss attributable to partners	$	(67,657	)	$	(94,995	)

Earnings per unit:
Net loss allocated to limited partner common units	$	(40,980	)	$	(50,612	)
Weighted average number of limited partner common units outstanding	48,562			34,161
Basic and diluted loss per common unit	$	(0.84	)	$	(1.48	)

Net loss allocated to limited partner subordinated units	$	(10,304	)	$	(18,089	)
Weighted average number of limited partner subordinated units outstanding	12,214			12,214
Basic and diluted loss per subordinated unit	$	(0.84	)	$	(1.48	)

See accompanying notes to these consolidated financial statements.

SOUTHCROSS ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



	Year Ended December 31,
	2017			2016
Cash flows from operating activities:
Net loss	$	(67,592	)	$	(94,948	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization	71,902			106,947
Unit-based compensation	1,375			3,523
Amortization of deferred financing costs and original issuance discount	3,569			3,354
Gain on sale of assets, net	(5		)	(11,768		)
Unrealized loss (gain) on financial instruments	2			(147		)
Equity in losses of joint venture investments	13,060			21,123
Distribution from joint venture investment	—			740
Impairment of assets	1,769			476
Gain on insurance proceeds	(1,508		)	—
Gain on legal settlements	—			(2,375		)
Write-off of deferred financing costs	—			1,006
Other, net	(474		)	(310		)
Changes in operating assets and liabilities:
Trade accounts receivable, including affiliates	(5,425		)	31,554
Prepaid expenses and other current assets	829			947
Other non-current assets	(58		)	(358		)
Accounts payable and accrued liabilities, including affiliates	9,257			(18,234		)
Other liabilities	(519		)	9,112
Net cash provided by operating activities	26,182			50,642
Cash flows from investing activities:
Capital expenditures	(22,790		)	(27,273		)
Aid in construction receipts	9,918			1,207
Insurance proceeds from property damage claims, net of expenditures	2,000			125
Net proceeds from sale of assets	3,409			22,470
Investment contributions to joint venture investments	(711		)	(5,433		)
Net cash used in investing activities	(8,174		)	(8,904		)
Cash flows from financing activities:
Borrowings under our credit facility	—			11,210
Repayments under our credit facility	(28,000		)	(70,350		)
Repayments under our term loan agreement	(5,353		)	(4,500		)
Payments on capital lease obligations	(487		)	(419		)
Financing costs	(44		)	(1,366		)
Tax withholdings on unit-based compensation vested units	(132		)	(138		)
Common unit issuances to Holdings for equity contributions	—			29,416
Borrowing of senior unsecured PIK notes	—			14,000
Repayment of senior unsecured PIK notes	—			(14,000		)
Valley Wells operating expense cap adjustments	—			4,053
Other, net	—			234
Net cash used in financing activities	(34,016		)	(31,860		)

Net increase (decrease) in cash and cash equivalents	(16,008		)	9,878
Cash and cash equivalents — Beginning of year	21,226			11,348
Cash and cash equivalents — End of year	$	5,218		$	21,226

See accompanying notes to these consolidated financial statements.

SOUTHCROSS ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL

(In thousands)



	Partners' Capital
	Limited Partners									General Partner
	Common			Class B Convertible			Subordinated			General Partner			Total
BALANCE - December 31, 2015	$	271,236		$	300,596		$	37,920		$	11,584		$	621,336
Net loss	(50,586		)	(24,383		)	(18,080		)	(1,899		)	(94,948		)
Unit-based compensation on long-term incentive plan	3,523			—			—			—			3,523
Accrued distribution equivalent rights on long-term incentive plan	11			—			—			—			11
Tax withholdings on unit-based compensation vested units	(138		)	—			—			—			(138		)
Common unit issuances to Holdings for equity cures and equity contributions	29,416			—			—			854			30,270
Interest on receivable from Holdings	—			—			—			233			233
Retention bonuses funded by Holdings	936			—			—			—			936
Valley Wells' operating expense cap adjustment	2,406			—			—			—			2,406
General partner unit in-kind distribution	(26		)	(12		)	(9		)	47			—
Class B Convertible unit in-kind distribution	(1,654		)	2,307			(591		)	(62		)	—
BALANCE - December 31, 2016	$	255,124		$	278,508		$	19,240		$	10,757		$	563,629
Net loss	(40,980		)	(14,956		)	(10,304		)	(1,352		)	(67,592		)
Unit-based compensation on long-term incentive plan	1,375			—			—			—			1,375
Tax withholdings on unit-based compensation vested units	(132		)	—			—			—			(132		)
Contributions from general partner	—			—			—			5			5
Retention bonuses funded by Holdings	2,281			—			—			—			2,281
General partner unit in-kind distribution	(40		)	(15		)	(10		)	65			—
Class B Convertible unit in-kind distribution	(2,482		)	3,188			(624		)	(82		)	—
BALANCE - December 31, 2017	$	215,146		$	266,725		$	8,302		$	9,393		$	499,566

See accompanying notes to these consolidated financial statements.

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1. ORGANIZATION, DESCRIPTION OF BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Organization and Description of Business

Southcross Energy Partners, L.P. (the "Partnership," "Southcross," "we," "our" or "us") is a Delaware limited partnership. Our common units are listed on the New York Stock Exchange under the symbol “SXE.” 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 two gas processing plants, one fractionation facility and gathering and transportation pipelines.

Southcross Holdings LP, a Delaware limited partnership (“Holdings”), indirectly owns 100% of Southcross Energy

Partners GP, LLC, a Delaware limited liability company, our General Partner (“General Partner”) (and therefore controls us),

all of our subordinated and Class B convertible units and 54.5% 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 (see Note 2), 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' term loan (the "Lenders") own the remaining one-third of Holdings.

The AMID Transactions

The Contribution Agreement contains customary representations and warranties and covenants by each of the parties. Holdings has also undertaken several additional obligations under the Contribution Agreement with respect to the Partnership and our subsidiaries. These include, without limitation, Holdings’ indemnification of AMID for certain obligations with respect to breaches of representations and warranties regarding the Partnership and our subsidiaries. In addition, Holdings is indemnifying AMID for certain contingent liabilities of the Partnership and our subsidiaries, including several ongoing litigation matters. A portion of the consideration, including approximately $25 million of the AMID Common Units to be received by Holdings will be deposited into escrow in order to secure the potential indemnification obligations until the longer of the end of 12 months from the closing of the Contribution Agreement, May 31, 2019 or the final resolution of the Special Indemnity Matters (as defined in the Contribution Agreement). In addition, all of the AMID Common Units, AMID Preferred Units and the Options received by Holdings as consideration under the Contribution Agreement will be subject to a lock-up agreement whereby such securities will be locked up until the longer of 12 months (with respect to the AMID Common Units) and 24 months (with respect to the AMID Preferred Units and Options) and, together with the AMID GP equity interests, the final resolutions of the Special Indemnity Matters (as defined in the Contribution Agreement). Further, during this time, cash distributions made by AMID or AMID GP to Holdings will be restricted, must remain within Holdings, and will be subject to recapture by AMID. The closing under the Contribution Agreement is conditioned upon, among other things: (i) expiration or

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termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the”HSR Act”), which was received on December 8, 2017, (ii) the absence of certain legal impediments prohibiting the transactions and (iii) with respect to AMID’s obligation to close only, the conditions precedent contained in the Merger Agreement having been satisfied and the Merger having become effective substantially concurrently with the closing of the Contribution Agreement.

The Contribution Agreement contains provisions granting both parties the right to terminate the Contribution Agreement for certain reasons. The Contribution Agreement further provides that, upon termination by Holdings of the Contribution Agreement in the event of a Funding Failure (as defined in the Contribution Agreement), AMID may be required to pay a reverse termination fee in an amount up to $17 million.

Segments

Our chief operating decision-maker is the Chief Executive Officer who reviews financial information presented on a consolidated basis in order to assess our performance and make decisions about resource allocations. There are no segment managers who are held accountable by the chief operating decision-maker, or anyone else, for operations, operating results and planning for levels or components below the consolidated unit level. Accordingly, we have determined that we have one reportable segment.

Basis of Presentation

The accompanying consolidated financial statements were prepared in accordance with accounting principles generally accepted in the U.S. ("GAAP") and in accordance with the rules and regulations of the U.S. Securities and Exchange Commission. Our consolidated financial statements include the accounts of Southcross and its 100% owned subsidiaries. We eliminate all intercompany balances and transactions in preparing consolidated financial statements.

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We evaluate events that occur after the balance sheet date, but before the financial statements are issued, for potential recognition or disclosure. Based on the evaluation, we determined that there were no material subsequent events for recognition or disclosure other than those disclosed in this report. See Note 14.

Principles of Consolidation

We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. We do not have ownership in any consolidated variable interest entities.

Use of Estimates

The preparation of the consolidated financial statements in conformity with GAAP requires management to make various estimates and assumptions that may affect the amounts of assets and liabilities, disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. Actual results may differ from those estimates.

Significant Accounting Policies

Revenue Recognition

Using the revenue recognition criteria of persuasive evidence of an exchange arrangement exists, delivery has occurred or services have been rendered and the price is fixed or determinable, we record natural gas and NGL sales revenue in the period when the physical product is delivered to the customer and in an amount based on the pricing terms of an executed contract. Our transportation, compression, processing, fractionation and other revenue is recognized in the period when the service is provided and represents our fee-based service revenue. In addition, collectability is evaluated on a customer-by-customer basis. New customers are subject to a credit review process, which evaluates the customers' financial position and their ability to pay.

We derive revenue in our business from the following types of arrangements:


•	Fixed-Fee. We receive a fixed-fee per unit of natural gas volume that we gather at the wellhead, process, treat, compress and/or transport for our customers, or we receive a fixed-fee per unit of NGL volume that we fractionate. Some of our arrangements also provide for a fixed-fee for guaranteed transportation capacity on our systems.

•

Commodity-Sensitive. In exchange for our processing services, we may remit to a customer a percentage of the proceeds from our sales, or a percentage of the physical volume, of residue natural gas and/or NGLs that result from our natural gas processing, or we may purchase NGLs from customers at set fixed NGL recoveries and retain the balance of the proceeds or physical commodity for our own account. These arrangements are generally combined with fixed-fee and fixed-spread arrangements for processing services and, therefore, represent only a portion of a processing contract's value. The revenues we receive from these arrangements directly correlate with fluctuating general commodity price levels of natural gas and NGLs and the volume of NGLs recovered relative to the fixed recovery obligations.

Certain of our gathering and processing agreements provide for quarterly and annual minimum volume commitment ("MVC"). Under these MVCs, our customers agree to ship and/or process a minimum volume of production on our gathering systems or to pay a minimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to us at the end of the contracted measurement period if its actual throughput volumes are less than its MVC for that period. Certain customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent

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measurement periods to the extent that such customer's throughput volumes in a subsequent contracted measurement period exceed its MVC for that contracted measurement period.

We recognize customer billings for obligations under their MVCs as revenue when the obligations are billable under the contract and the customer does not have the right to utilize shortfall payments to offset gathering fees in excess of its MVCs in subsequent periods.

We record customer billings for obligations under their MVCs as deferred revenue when the customer has the right to utilize shortfall payments to offset gathering or processing fees in subsequent periods. We recognize deferred revenue under these arrangements in revenue once all contingencies or potential performance obligations associated with the related volumes have either (i) been satisfied through the gathering or processing of future excess volumes of natural gas, or (ii) expired (or lapsed) through the passage of time pursuant to the terms of the applicable natural gas gathering agreement.

We classify deferred revenue as a current liability for arrangements where the expiration of a customer's right to utilize shortfall payments is 12 months or less.

Long-Lived Assets

Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead and the cost of financing construction. Costs associated with obtaining rights of way agreements and easements to facilitate the building and maintenance of new pipelines are capitalized and depreciated over the life of the associated pipeline. We capitalize major units of property replacements or improvements and expense minor items. We use the straight-line method to depreciate property, plant and equipment over the estimated useful lives of the assets. We depreciate leasehold improvements and capital lease assets over the shorter of the life of the asset or the life of the lease. Maintenance and repairs are charged directly to expense as incurred, with the exception of substantial compression overhaul costs, which are capitalized and depreciated over the life of the overhaul.

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

Impairment of Long-Lived Assets

Cash and Cash Equivalents

We consider all short-term investments with an original maturity of three months or less to be cash equivalents. At December 31, 2017 and 2016, except for amounts held in bank accounts to cover current payables, all of our cash equivalents were invested in short-term money market accounts and overnight sweep accounts.

Allowance for Doubtful Accounts

In evaluating the collectability of our accounts receivable, we perform credit evaluations of our new customers and adjust payment terms based upon payment history and each customer's current creditworthiness, as determined by our review of such customer's credit information. We extend credit on an unsecured basis to many of our customers. In the event of a bankruptcy filing by a customer, we will determine if we will legally be able to collect any of the outstanding balance as a secured or unsecured creditor, and based on this determination we will reserve against part, or all, of the outstanding balance. We had an allowance for uncollectible accounts receivable of $0.1 million at December 31, 2015, which was written off during 2016. We had no allowance for uncollectible accounts receivable at December 31, 2017.

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Asset Retirement Obligations

We evaluate whether any future asset retirement obligations ("AROs") exist and estimate the costs for such AROs for certain future events. An ARO will be recorded in the periods where we can reasonably determine the settlement dates or the period in which the expense is incurred, and an estimated cost of the retirement obligation. Generally we do not have the intention of discontinuing the use of any significant assets or have a legal obligation to do so. Therefore, in these situations we do not have sufficient information to reasonably estimate any future AROs. No AROs were recorded for the years ended December 31, 2017 and 2016.

Environmental Costs and Other Contingencies

We recognize liabilities for environmental and other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and no specific amount in that range is more likely than any other, the low end of the range is accrued. No amounts were recorded as of December 31, 2017 and 2016.

Fair Value of Financial Instruments

Accounting guidance requires the disclosure of the fair value of all financial instruments that are not otherwise recorded at fair value in the financial statements. At December 31, 2017 and 2016, financial instruments recorded at contractual amounts that approximate fair value include certain funds on deposit, accounts receivable, other receivables and accounts payable and accrued liabilities. The fair values of such items are not materially sensitive to shifts in market interest rates because of the short term to maturity of these instruments. See Note 4.

Derivative Instruments

We manage our interest rate risk through interest rate swaps and interest rate caps. Derivative financial instruments are recorded in the consolidated balance sheets at fair value, except for derivative contracts that qualify for and for which we have elected the normal purchase or normal sale exceptions, which are not reflected in the consolidated balance sheets or statements of operations prior to accrual of the settlement. If they qualify, we present our derivative assets and liabilities on a net basis. See Note 4.

We did not have any derivative financial instruments designated as fair value or cash flow hedges for accounting purposes during the years ended December 31, 2017 and 2016. Changes in our derivative financial instruments' fair values are recognized immediately in earnings. We do not hold or issue financial instruments or derivative financial instruments for trading purposes.

Unit-Based Compensation

Unit-based awards which settle in common units are classified as equity and are recognized in the financial statements over the vesting period at their grant date fair value. Unit-based awards which settle in cash are classified as liabilities and remeasured at every balance sheet date through settlement, such that the vested portion of the liability is adjusted to reflect its revised fair value through compensation expense. Currently, all awards granted under the Amended and Restated 2012 Long-Term Incentive Plan (the “LTIP”) will be settled in common units. Compensation expense associated with unit-based awards, adjusted for forfeitures, is recognized evenly from the date of the grant over the vesting period within operations and maintenance and general and administrative expense in our consolidated statements of operations.

Income Taxes

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

We are subject to the Texas margin tax which qualifies as an income tax under GAAP that requires us to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis. Our current tax liability will be assessed based on the gross revenue apportioned to Texas. For the years ended December 31, 2017 and 2016, there were no material temporary differences.

Uncertain Tax Positions

We evaluate the uncertainty in tax positions taken or expected to be taken in the course of preparing our consolidated

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financial statements to determine whether the tax positions are more likely than not of being sustained by the applicable tax authority. We believe that there are no uncertain tax positions and that no provision for income tax is required for these consolidated financial statements. As of December 31, 2017, tax years 2013 through 2017 remain subject to examination by the Internal Revenue Service and tax years 2012 through 2017 remain subject to examination by various state taxing authorities.

Earnings per Unit

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

Basic net loss per unit excludes dilution and is computed by dividing net loss attributable to limited partner common units by the weighted average number of limited partner common units outstanding during the period. Paid-in kind distributions are excluded from income available to common units in the calculation of basic earnings per unit. Dilutive net loss per unit reflects potential dilution from the potential issuance of limited partner common units. Dilutive net loss per unit is calculated using the treasury stock method. It is computed by dividing net loss attributable to limited partner common units by the weighted average number of limited partner common units outstanding during the period increased by the number of additional limited partner common units that would have been outstanding if the dilutive potential limited partner common units had been issued.

Comprehensive Income (Loss)

Comprehensive income (loss) is the same as net income (loss) for periods presented in the consolidated financial statements.

Investments in Joint Ventures

We own equity interests in three joint ventures with Targa Resources Corp. ("Targa") as our joint venture partner. We own a 50% or less equity interest in each of the three entities. The joint venture arrangements give equal management rights with no single investor having unilateral control. Each party sharing joint control must consent to the ventures’ operating, investing and financing decisions. Therefore, because we do not have controlling financial interests, but do have significant influence, we use the equity method of accounting for investments in joint ventures. We recognize our share of the earnings and losses in the joint ventures pursuant to the terms of the applicable limited liability agreements governing such joint ventures, which provide for earnings and losses generally to be allocated based upon each member’s respective ownership interest in the joint ventures. We record our proportionate share of the joint ventures’ net income/loss as equity in income/losses of joint venture investments in the statements of operations. We evaluate investments in joint ventures for impairment when factors indicate that a decrease in the value of the investment has occurred that is not temporary. During the fourth quarter of 2016, as part of our cost-saving initiatives, management decided to significantly reduce the utilization of the T2 EF Cogeneration ("T2 Cogen") facility. In the immediate future, the T2 Cogen facility will only be utilized as a swing or backup facility for our Lone Star processing facility. As volumes are expected to increase in the ensuing years, management expects to need the generation capacity from the T2 Cogen facility to provide power to its Lone Star processing facility. As of December 31, 2017, management has no intention or plans to “mothball” or sell the T2 Cogen facility. See Note 12.

Recent Accounting Pronouncements

Accounting standard-setting organizations frequently issue new or revised accounting pronouncements. We review and evaluate new pronouncements and existing pronouncements to determine their impact, if any, on our consolidated financial statements. We are evaluating the impact of each pronouncement on our consolidated financial statements.

Adopted Accounting Pronouncements

In March 2016, a pronouncement was issued amending the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. We adopted this standard, which did not have a material impact to us, in 2017.

In March 2016, the FASB issued a pronouncement amending the requirement to adopt retroactively the equity method of accounting. The pronouncement eliminates the requirement that when an investment qualifies for use of the equity method as a result of an increase in the level of ownership interest or degree of influence, an investor must adjust the investment, results of operations, and retained earnings retroactively on a step-by-step basis as if the equity method had been in effect during all previous periods that the investment had been held. The new guidance requires that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor’s previously held interest and adopt the equity method of accounting as of the date the investment becomes qualified for equity method accounting. Therefore, upon qualifying for the equity method of accounting, no retroactive adjustment of the investment is required. In addition, the

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pronouncement requires that an entity that has an available-for sale equity security that becomes qualified for the equity method of accounting recognize through earnings the unrealized holding gain or loss in accumulated other comprehensive income at the date the investment becomes qualified for use of the equity method. SXE owns equity interests in three joint ventures with Targa as SXE's joint venture partner. T2 Eagle Ford Gathering Company LLC (“T2 Eagle Ford”), T2 LaSalle Gathering Company LLC (“T2 LaSalle”) and Cogen operate pipelines and a cogeneration facility located in South Texas. SXE indirectly owns a 50% interest in T2 Eagle Ford, a 50% interest in T2 Cogen and a 25% interest in T2 LaSalle. SXE pays its proportionate share of the joint ventures’ operating costs, excluding depreciation and amortization, through lease capacity payments. As a result, SXE's share of the joint ventures’ losses is related primarily to the joint ventures’ depreciation and amortization. SXE's maximum exposure to loss related to these joint ventures includes its equity investment, any additional capital contributions and its share of any operating expenses incurred by the joint ventures. During the year ended December 31, 2017 we have acquired no additional level of ownership interests in SXE's three joint ventures with Targa, thus, no incremental cost needs to be recorded to the current basis of the T2 entities. We adopted this standard, which did not have a material impact to us, in 2017. See Note 13 to our combined financial statements.

In August 2016, the FASB issued a pronouncement amending the presentation of how certain cash receipts and cash payments are presented and classified in the statement of cash flows. We early adopted this standard in 2017 and reclassified $0.3 million of paid-in kind interest from financing to operating cash flows for 2016.

New Accounting Pronouncements

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

In 2014, a comprehensive new revenue recognition standard that will supersede substantially all existing revenue recognition guidance under GAAP was issued. The standard's core principle is that a company will recognize revenue when it transfers promised goods or services to customers and in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In April 2016, the FASB issued an accounting pronouncement which updates the identifying performance obligations and licensing implementation guidance. We have evaluated our contract mix, developed our implementation plan and are assessing the impact to our existing financial statement disclosures. The standard will become effective beginning in 2018, and is not expected to have a material impact to our financial statements.

In May 2016, the FASB issued a pronouncement for the new revenue recognition guidance on assessing collectability, presentation of sales taxes, non-cash consideration, completed contracts and contract modifications. The pronouncement is intended to reduce the potential for diversity in practice at initial application and cost and complexity on an ongoing basis. The standard will become effective beginning in 2018.

2. LIQUIDITY CONSIDERATIONS

Our future cash flow will be materially adversely affected if the prices for natural gas, NGL and crude oil continue to affect the drilling for oil or natural gas in our primary operating area, the Eagle Ford Shale. See Note 1 to our consolidated financial statements. The majority of our revenue is derived from fixed-fee and fixed-spread contracts, which have limited direct exposure to commodity price levels since we are paid based on the volumes of natural gas that we gather, process, treat, compress and transport and the volumes of NGLs we fractionate and transport, rather than being paid based on the value of the underlying natural gas or NGLs. In addition, a portion of our contract portfolio contains minimum volume commitment arrangements. The majority of our volumes are dependent upon the level of producer drilling activity. We remain focused on our efforts to improve future liquidity, and have implemented cost-saving initiatives in 2016 and 2017 to lower our operating and general and administrative cost structure. Additionally, we have explored various strategic options resulting in the Merger Agreement and Contribution Agreement.

In connection with Holdings' Chapter 11 reorganization, we entered into an equity cure contribution agreement (the “Equity Cure Agreement”) with Holdings that allowed us to cure any default under applicable Financial Covenants by having Holdings purchase equity interests in or make capital contributions to us, in an aggregate amount of up to $50 million (the

"Contribution Amount"). In exchange for the Contribution Amount, we issued Holdings a number of our common units representing limited partner interests equal to, subject to certain exceptions, (i) the applicable Contribution Amount divided by (ii) a common unit reference price (“Reference Price”) equal to the volume weighted daily average price of the common units on the New York Stock Exchange (“VWAP”) calculated for a period of 15 trading days ending two trading days prior to the contribution by Holdings. Notwithstanding the VWAP calculation, the Reference Price would be no less than $0.89 per common unit and no greater than $1.48 per common unit (the “Range”), and if the VWAP was within the Range for a period of 15 trading days, the first of which was April 7, 2016, such VWAP would be the Reference Price for all common units issued in exchange for the Contribution Amount. The Equity Cure Agreement remained in place throughout 2016 and was used to fund equity cures totaling $12.4 million (excluding the $17.0 million discussed below) required to comply with the Consolidated Total Leverage Ratio of our Financial Covenants. See Note 9 for further discussion of our equity cure unit issuances.

On July 25, 2016, we determined Holdings’ cash contribution to us for the first quarter 2016 equity cure had not been transferred to us timely, as required under the Third Amended and Restated Revolving Credit Agreement with Wells Fargo, N.A., UBS Securities LLC, Barclays Bank PLC and a syndicate of lenders (the "Third A&R Revolving Credit Agreement"), due to an administrative oversight, which resulted in a default. On July 26, 2016, Holdings fully funded the first quarter 2016 equity cure. On August 4, 2016, we entered into the limited waiver and second amendment to the Third A&R Revolving Credit Agreement whereby the lenders waived any default or right to exercise any remedy as a result of this technical event of default to fund timely the first quarter 2016 equity cure.

On November 8, 2016, we entered into a limited waiver and third amendment to the Third A&R Revolving Credit Agreement (the “Third Amendment”), which stipulated, among other things, that (i) the equity cure funding deadline for the quarter ended September 30, 2016 (“Q3 2016 Equity Cure”) was extended from November 23, 2016 to December 16, 2016, and (ii) limited the total revolving credit exposure. On December 9, 2016, we entered into the fourth amendment to the Third A&R Revolving Credit Agreement (the "Fourth Amendment"), which stipulated, among other things, that (i) the deadline for funding the Q3 2016 Equity Cure was further extended from December 16, 2016 to January 12, 2017, and (ii) the Third A&R Revolving Credit Agreement was amended to require that any account into which we deposited funds, securities or commodities be subject to a lien and control agreement for the benefit of the secured parties under the Third A&R Revolving Credit Agreement.

On December 29, 2016, we entered into the fifth amendment (the "Fifth Amendment") to the Third A&R Revolving Credit Agreement, pursuant to which we received a full waiver for all defaults or events of default arising out of our failure to comply with the financial covenant to maintain a Consolidated Total Leverage Ratio (as defined in the Fifth Amendment) less than 5.00 to 1.00 for the quarter ended September 30, 2016.

Additionally, pursuant to the Fifth Amendment, (i) the total aggregate commitments under the Third A&R Revolving Credit Agreement were reduced from $200 million to $135 million (then further reduced to $125 million on March 31, 2018) and the sublimit for letters of credit was also reduced from $75 million to $50 million (total aggregate commitments will be periodically further reduced through December 31, 2018); (ii) the Consolidated Total Leverage Ratio and Consolidated Senior Secured Leverage Ratio (each as defined in the Fifth Amendment) financial covenants were suspended until the quarter ending March 31, 2019; and (iii) the Consolidated Interest Coverage Ratio (as defined in the Fifth Amendment) financial covenant requirement was reduced from 2.50 to 1.00 to 1.50 to 1.00 for all periods ending on or prior to December 31, 2018 (the “Ratio Compliance Date”). Prior to the Ratio Compliance Date, we will be required to maintain minimum levels of Consolidated EBITDA (as defined in the Fifth Amendment) on a quarterly basis and be subject to certain covenants and restrictions related to liquidity and capital expenditures. See Note 6 to our consolidated financial statements.

In connection with the execution of the Fifth Amendment, on December 29, 2016, the Partnership entered into (i) an Investment Agreement (the "Investment Agreement") with Holdings and Wells Fargo Bank, N.A., (ii) a Backstop Agreement (the "Backstop Agreement") with Holdings, Wells Fargo Bank, N.A. and the Sponsors and (iii) a First Amendment to Equity Cure Contribution Agreement (the "Equity Cure Contribution Amendment") with Holdings. Pursuant to the Equity Cure Contribution Amendment, on December 29, 2016, Holdings contributed $17.0 million to us in exchange for 11,486,486 common units. The proceeds of the $17.0 million contribution were used to pay down the outstanding balance under the Third A&R Revolving Credit Agreement and for general corporate purposes. In addition, on January 2, 2018, we notified Holdings that a Full Investment Trigger (as defined in the Investment Agreement) occurred on December 31, 2017. Pursuant to the Backstop Agreement, on January 2, 2018, Holdings delivered a Backstop Demand (as defined in the Investment Agreement) for each Sponsor to fund their respective pro rata portions of the Sponsor Shortfall Amount (as defined in the Investment Agreement) of $15.0 million in accordance with the Backstop Agreement. As consideration for the amount provided directly to us by the Sponsors pursuant to the Backstop Agreement, we issued to the Sponsors senior unsecured notes of the Partnership in an aggregate principal amount of $15.0 million (each, an "Investment Note" and collectively, the “Investment Notes”). The Investment Notes mature on November 5, 2019 and bear interest at a rate of 12.5% per annum. Interest on the Investment Notes shall be paid in kind (other than with respect to interest payable (i) on or after the maturity date, (ii) in connection with

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prepayment, or (iii) upon acceleration of the Investment Note, which shall be payable in cash); provided that all interest shall be payable in cash on or after December 31, 2018. The Investment Notes are the unsecured obligation of the Partnership subordinate in right of payment to any of our secured obligations under the Third A&R Revolving Credit Agreement.

Based upon the Partnership's financial forecast, the Fifth Amendment, as well as the $15.0 million provided by the Sponsors in exchange for the Investment Notes, we believe management's executed plans provide the Partnership with sufficient liquidity to fund future operations through at least twelve months from the date that these financial statements were issued.

However, during management's ongoing assessment of the Partnership's financial forecast, the Holdings GP Board and the SXE GP Board considered that in our corporate structure and absent continued access to equity cures from our Sponsors or a significant equity infusion from a third party, which the Partnership may not be able to obtain, or absent additional amendments to its Revolving Credit Agreement or waivers of the March 31, 2019 requirement to comply with the Consolidated Total Leverage Ratio (as defined in the Fifth Amendment), the Partnership is not expected to be able to comply with such financial covenant as of such date, which would trigger an event of default, and result in substantial doubt regarding SXE’s ability to continue as a going concern as early as the end of the first quarter of 2018. If the Partnership's independent registered public accounting firm reports in a subsequent audit report the existence of substantial doubt regarding the Partnership's ability to continue as a going concern, this would also lead to an event of default under the Partnership's Revolving Credit Agreement and Term Loan which, in turn, would trigger a cross default under Southcross Holdings Borrowers' credit facilities. Such events of default, if not cured, would allow the lenders under each of these borrowing arrangements to accelerate the maturity of the debt, making it due and payable immediately.

3. NET LOSS PER LIMITED PARTNER UNIT AND DISTRIBUTIONS

Net Loss Per Limited Partner Unit

The following is a reconciliation of net loss attributable to limited partners and the limited partner units used in the basic and diluted earnings per unit calculations for the years ended December 31, 2017 and 2016 (in thousands, except unit and per unit data):



	Year Ended December 31,
	2017			2016
Net loss	$	(67,592	)	$	(94,948	)
General partner unit in-kind distribution	(65		)	(47		)
Net loss attributable to partners	$	(67,657	)	$	(94,995	)

General partner's interest⁽¹⁾	$	(1,417	)	$	(1,911	)
Class B Convertible limited partner interest⁽¹⁾	(14,956		)	(24,383		)
Limited partners' interest⁽¹⁾
Common	$	(40,980	)	$	(50,612	)
Subordinated	(10,304		)	(18,089		)

_____________________________________________________________


(1)	General Partner's and limited partners’ interests are calculated based on the allocation of net losses for the period, net of the General Partner unit in-kind distributions. The Class B Convertible Unit interest is calculated based on the allocation of only net losses for the period.

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	Year Ended December 31,
Common Units	2017			2016
Interest in net loss	$	(40,980	)	$	(50,612	)
Effect of dilutive units - numerator⁽¹⁾	—			—
Dilutive interest in net loss	$	(40,980	)	$	(50,612	)

Weighted-average units - basic	48,562,193			34,160,860
Effect of dilutive units - denominator⁽¹⁾	—			—
Weighted-average units - dilutive	48,562,193			34,160,860

Basic and diluted net loss per common unit	$	(0.84	)	$	(1.48	)



	Year Ended December 31,
Subordinated Units	2017			2016
Interest in net loss	$	(10,304	)	$	(18,089	)
Effect of dilutive units - numerator⁽¹⁾	—			—
Dilutive interest in net loss	$	(10,304	)	$	(18,089	)

Weighted-average units - basic	12,213,713			12,213,713
Effect of dilutive units - denominator⁽¹⁾	—			—
Weighted-average units - dilutive	12,213,713			12,213,713

Basic and diluted net loss per subordinated unit	$	(0.84	)	$	(1.48	)

____________________________________________________________________________

(1)

Because we had a net loss for all periods for common units and the subordinated units, the effect of the dilutive units would be anti-dilutive to the per unit calculation. Therefore, the weighted average units outstanding are the same for basic and dilutive net loss per unit for those periods. The weighted average units that were not included in the computation of diluted per unit amounts were 43,811 and 19,453 and unvested awards granted under our LTIP for the years ended December 31, 2017 and 2016, respectively.

Our calculation of the number of weighted-average units outstanding includes the common units that have been awarded

to our directors that are deferred under our Non-Employee Director Deferred Compensation Plan (the “Plan”). In connection

with the execution of the Merger Agreement, the board of directors of our General Partner approved an amendment (the

“Amendment”) to the Plan. In connection with and pursuant to the terms of the Merger Agreement, the Partnership is required

to terminate the Plan and liquidate the sole participant’s account within 30 days prior to the closing of the Merger. The

Amendment terminates the Plan effective as of one business day prior to the closing of the Merger and provides that the

participant’s account will be liquidated and paid to the participant or his beneficiary, if applicable, in the form of a lump sum

cash payment as soon as practical following the effective time of the Merger. The Amendment will be null and void in the event

that the closing of the Merger does not occur.

Distributions

Cash Distributions

Our agreement of limited partnership (as amended and restated, the “Partnership Agreement”), requires that within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date, as determined by our General Partner. There is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Beginning with the third quarter of 2014, until such time that we have a distributable cash flow divided by cash distributions ratio (“Distributable Cash Flow Ratio”) of at least 1.0, Holdings, the indirect holder of all of our subordinated units, waived the right to receive distributions on any subordinated units that would cause the Distributable Cash Flow Ratio to be less than 1.0. More importantly, the First Amendment (as defined in Note 6) imposed additional restrictions on our ability to declare and pay quarterly cash distributions with respect to our subordinated units. Additionally, we are restricted under the

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Fifth Amendment from paying a distribution with respect to our common units until our Consolidated Total Leverage Ratio is below 5.0. See Note 6 to the consolidated financial statements.

Paid In-Kind Distributions

Class B Convertible Units. As of December 31, 2017, the Class B Convertible Units consisted of 18,335,181 of such units including the additional Class B Convertible Units issued in-kind as a distribution (“Class B PIK Units”). The Class B Convertible Units are not participating securities for purposes of the earnings per unit calculation. Commencing with the quarter ended September 30, 2014 and until converted, as long as certain requirements are met, the holders of the Class B Convertible Units will receive quarterly distributions in an amount equal to $0.3257 per unit. These distributions will be paid quarterly in Class B PIK Units within 45 days after the end of each quarter. Our General Partner was entitled, and has exercised its right, to retain its 2.0% general partner interest in us in connection with the original issuance of Class B Convertible Units. In connection with future distributions of Class B PIK Units, the General Partner is entitled to a corresponding distribution to maintain its 2.0% general partner interest in us. The Class B Convertible Units have the same rights, preferences and privileges, and are subject to the same duties and obligations, as our common units, with certain exceptions. See Note 9.

The following table represents the PIK distribution paid on the Class B Convertible Units for periods ended December 31, 2017 and 2016 (in thousands, except per unit and in-kind distribution units):



Payment Date	Attributable to the Quarter Ended	Per Unit Distribution		In-Kind Class B Convertible Unit Distributions to Class B Convertible Holders	In-Kind Class B Convertible Distributions Value⁽¹⁾		In-Kind Unit Distribution to General Partner	In-Kind General Partner Distribution Value⁽¹⁾
2017
February 9, 2018	December 31, 2017	$	0.3257	320,890	542		6,549	11
November 11, 2017	September 30, 2017	0.3257		315,370	741		6,436	15
August 11, 2017	June 30, 2017	0.3257		309,946	983		6,325	20
May 11, 2017	March 31, 2017	0.3257		304,615	1,060		6,216	22
2016
February 14, 2017	December 31, 2016	$	0.3257	299,375	$	404	6,109	$	8
November 24, 2016	September 30, 2016	0.3257		294,226	433		6,004	9
August 10, 2016	June 30, 2016	0.3257		289,165	581		5,901	12
May 9, 2016	(2)	0.3257		563,494	1,293		11,499	26


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

(2)

We suspended distributions to holders of our Class B Convertible Units for the quarters ended December 31, 2015 and March 31, 2016. However, under the terms of our Partnership agreement, such paid in-kind (“PIK”) distributions continued to accumulate. On May 9, 2016, we issued the accumulated Class B Convertible Units to Holdings and general partner units to our General Partner related to the quarters ended December 31, 2015 and March 31, 2016.

4. FINANCIAL INSTRUMENTS

Fair Value Measurements

We apply recurring fair value measurements to our financial assets and liabilities. In estimating fair value, we generally

use a market approach and incorporate assumptions that market participants would use in pricing the asset or liability, including

assumptions about risk and/or the risks inherent in the inputs to the valuation techniques. The fair value measurement inputs we

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use vary from readily observable inputs that represent market data obtained from independent sources to unobservable inputs

that reflect our own market assumptions that cannot be validated through external pricing sources. Based on the observability

of the inputs used in the valuation techniques, the financial assets and liabilities carried at fair value in the financial statements

are classified as follows:


•	Level 1—Represents unadjusted quoted market prices in active markets for identical assets or liabilities that are

accessible at the measurement date. This category primarily includes our cash and cash equivalents.


•	Level 2—Represents quoted market prices for similar assets or liabilities in active markets, quoted market prices in

markets that are not active or other inputs that are observable or can be corroborated by observable market data. This

category primarily includes variable rate debt, over-the-counter swap contracts based upon natural gas price indices

and interest rate derivative transactions.


•	Level 3—Represents derivative instruments whose fair value is estimated based on internally developed models and

methodologies utilizing significant inputs that are generally less readily observable from market sources. We do not

have financial assets and liabilities classified as Level 3.

In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such

cases, the level in the fair value hierarchy must be determined based on the lowest level input that is significant to the fair value

measurement. An assessment of the significance of a particular input to the fair value measurement in its entirety requires

judgment and consideration of factors specific to the asset or liability.

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable represent fair values based on the short-term nature of these instruments. The fair value of our Credit Facility (defined in Note 6) approximates its carrying amount due primarily to the variable nature of the interest rate of the instrument and is considered a Level 2 fair value measurement. As of December 31, 2017, the fair value of our term loan was $425.1 million, based on recent trading levels and is considered a Level 2 fair value instrument.

Derivative Financial Instruments

Interest Rate Derivative Transactions

We enter into interest rate cap contracts to limit our London Interbank Offered Rate ("LIBOR") based interest rate risk on the portion of debt hedged at the contracted cap rate. Our interest rate cap position was as follows (in thousands):



					Estimated Fair Value
Notional Amount	Cap Rate		Effective Date	Maturity Date	December 31, 2017
50,000	3.000	%	June 30, 2016	June 30, 2018	—
40,000	3.000	%	December 31, 2016	January 1, 2018	—
40,000	3.000	%	December 31, 2016	July 1, 2018	—
40,000	3.000	%	December 31, 2016	January 1, 2019	—
60,000	3.000	%	June 30, 2017	June 30, 2019	2
85,000	3.000	%	December 31, 2017	June 30, 2018	—
					$	2

These interest rate derivatives are not designated as cash flow hedging instruments for accounting purposes and as a result, changes in the fair value are recognized in interest expense immediately.

The fair value of our interest rate derivative transactions is determined based on a discounted cash flow method using contractual terms of the transactions. The floating coupon rate is based on observable rates consistent with the frequency of the interest cash flows. We have elected to present our interest rate derivatives net on the balance sheets. There was no effect of offsetting in the balance sheets as of December 31, 2017 and 2016.

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The fair values of our interest rate derivative transactions were as follows (in thousands):



	Significant Other Observable Inputs (Level 2)
	Fair Value Measurement as of
	December 31, 2017		December 31, 2016
Current interest rate derivative assets	$	1	$	2
Non-current interest rate derivative assets	1		2
Current and non-current interest rate derivative (liabilities)	—		(15		)
Total interest rate derivatives	$	2	$	(11	)

The realized and unrealized amounts recognized in interest expense associated with derivatives were as follows (in thousands):



	Year Ended December 31,
	2017			2016
Unrealized loss (gain) on interest rate derivatives	$	2		$	(147	)
Realized loss (gain) on interest rate derivatives	(15		)	283

5. LONG-LIVED ASSETS

Property, Plant and Equipment

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



	Estimated Useful Life	As of December 31,
	Estimated Useful Life	2017			2016
Pipelines	15-30	$	571,730		$	552,540
Gas processing, treating and other plants	15	520,765			509,840
Compressors	5-15	78,997			72,054
Rights of way and easements	15	49,897			49,998
Furniture, fixtures and equipment	5	9,746			9,269
Capital lease vehicles	3-5	2,114			1,713
Total property, plant and equipment		1,233,249			1,195,414
Accumulated depreciation and amortization		(334,528		)	(262,709		)
Total		898,721			932,705

Construction in progress		2,173			16,150
Land and other		13,653			22,431
Property, plant and equipment, net		$	914,547		$	971,286

Depreciation is provided using the straight-line method based on the estimated useful life of each asset. Depreciation expense for the year ended December 31, 2017 and 2016, was $71.9 million and $106.9 million, respectively. Depreciation expense for the year ended December 31, 2016 included $32.5 million (the earnings per unit equivalent of $0.51 for the year ended December 31, 2016) of accelerated depreciation resulting from the assets' shortened useful life due to shutting down the Conroe facility and converting the Gregory facility to a compressor station in 2016. In May 2016, we finalized the sale of a portion of pipeline for $15.0 million, which was determined to be a sale of assets. We recorded a $13.6 million gain on sale of assets in our consolidated statement of operations in connection with this sale.

As part of Partnership-wide cost-saving initiatives, in December 2016 we shut down our Conroe processing plant

(“Conroe”) and converted our Gregory cryogenic processing plant (“Gregory”) into a compressor station. The gas previously

processed at Gregory has been re-rerouted to our Woodsboro processing facility beginning in the fourth quarter of 2016. During

the year ended December 31, 2017, we sold $2.1 million of the assets associated with Conroe and Gregory. As a result, we recorded an impairment of $1.1 million during the year ended December 31, 2017, to adjust these assets to fair value.

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In an effort to further our cost-saving initiatives, management elected to idle the Bonnie View fractionation facility

(“Bonnie View”) in the second quarter of 2017. As a result, all of our Y-grade product is sold to Holdings in accordance

with our affiliate Y-grade sales agreement and is being fractionated at the Holdings’ Robstown fractionation facility

(“Robstown”). We plan to utilize Bonnie View as a backup option to the extent Robstown is unable to fractionate our Y-grade

product and, therefore, we plan to spend an immaterial amount of capital during the year ending December 31, 2018, to ensure Bonnie View remains available in the future. Our election to idle Bonnie View has not had a material impact to our fourth quarter of 2017 earnings and cash flows, and is not expected to have a material impact on our future earnings and cash flows.

In January 2015, we shut down Gregory for four weeks due to a fire at the facility. In December 2016, we reached a settlement related to the Gregory fire with our insurance carriers. We received the payment of $2.0 million from our insurance carriers in the first quarter of 2017 and recorded a $1.5 million gain related to insurance proceeds received in excess of expenditures incurred to repair Gregory. As stipulated in the Term Loan Agreement (defined in Note 6), we used $1.0 million ($2.0 million of proceeds, net of the 2015 insurance deductible of $0.5 million and additional expenditures to repair Gregory of $0.5 million) of the proceeds to make a mandatory prepayment on our term loan.

Intangible Assets

Intangible assets of $1.3 million and $1.4 million as of December 31, 2017 and 2016, respectively, represent the unamortized value acquired to long-term supply and gathering contracts. These intangible assets are amortized on a straight-line basis over the 30-year expected useful lives of the contracts through 2041. Amortization expense over the next five years related to intangible assets is not significant.

6. LONG-TERM DEBT

Our outstanding debt and related information at December 31, 2017 and 2016 is as follows (in thousands):



	As of December 31,
	2017			2016
Revolving credit facility due 2019	$	94,555		$	122,555
Term loans due 2021	433,396			438,749
Original issuance discount on term loans due 2021	(1,134		)	(1,458		)
Total long-term debt (including current portion)	526,817			559,846
Current portion of long-term debt	(4,256		)	(4,500		)
Debt issuance costs	(8,295		)	(11,474		)
Total long-term debt	$	514,266		$	543,872
Outstanding letters of credit	$	24,911		$	19,378
Remaining unused borrowings	$	15,534		$	3,067



	Year Ended December 31,
	2017			2016
Weighted average interest rate	6.09		%	5.25		%
Average outstanding borrowings	$	544,112		$	591,970
Maximum borrowings	$	561,305		$	628,055



		Total		2018		2019		2020		2021		Thereafter
Maturity
	Long-term debt	$	527,951	$	4,256	$	98,811	$	4,256	$	420,628	$	—

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Senior Credit Facilities

Our long-term debt arrangements consist of (i) the Third A&R Revolving Credit Agreement (as defined in Note 2) and (ii) a Term Loan Credit Agreement with Wilmington Trust, National Association, UBS Securities LLC and Barclays Bank PLC and a syndicate of lenders (the “Term Loan Agreement” and, together with the Third A&R Revolving Credit Agreement, the “Senior Credit Facilities”). Substantially all of our assets are pledged as collateral under the Senior Credit Facilities, with the security interest of the facilities ranking pari passu.

Third A&R Revolving Credit Agreement

The Third A&R Revolving Credit Agreement is a five-year $200 million revolving credit facility due August 4, 2019 (the “Credit Facility”). Borrowings under our Credit Facility bear interest at the LIBOR plus an applicable margin or a base rate as defined in the Third A&R Revolving Credit Agreement. Pursuant to the Third A&R Revolving Credit Agreement, among other things:


(a)	the letters of credit sublimit was set at $75.0 million;


(b)	if we fail to comply with the Consolidated Total Leverage Ratio, Consolidated Senior Secured Leverage Ratio and

the Consolidated Interest Coverage Ratio covenants (each as defined in the Third A&R Revolving Credit

Agreement, and collectively the “Financial Covenants”) (each such failure, a “Financial Covenant Default”), we

have the right (a limited number of times) to cure such Financial Covenant Default by having the Sponsors

purchase equity interests in or make capital contributions to us resulting in, among other things, proceeds that, if

added to Consolidated EBITDA (as defined in the Third A&R Revolving Credit Agreement) would result in us

satisfying the Financial Covenants.

Amendments to Third A&R Revolving Credit Agreement

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

The First Amendment, among other things:

(i) (a) revised the maximum Consolidated Total Leverage Ratio set at 5.00 to 1.0 as of the last day of each fiscal quarter after September 30, 2016, without any step-ups in connection with acquisitions;

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

(iii) allowed us an unlimited number of quarterly equity cures related to our Financial Covenant Default through the fourth quarter of 2016, and no more than two in a twelve month period thereafter for the life of the agreement. Beginning on January 1, 2017, we are limited to no more than four equity cures, with no more than two in a twelve month period.

On July 25, 2016, we determined Holdings’ cash contribution to us for the first quarter 2016 equity cure had not been

timely transferred to us, as required under the Third A&R Revolving Credit Agreement, due to an administrative oversight,

which resulted in a default. On July 26, 2016, Holdings fully funded the first quarter 2016 equity cure. On August 4, 2016, we

entered into the limited waiver and second amendment to the Third A&R Revolving Credit Agreement whereby the lenders

waived any default or right to exercise any remedy as a result of this technical event of default to fund timely the first quarter

2016 equity cure.

On November 8, 2016, we entered into the third amendment to the Third A&R Revolving Credit Agreement (the "Third Amendment") which stipulated, among other things, that (i) the equity cure funding deadline for the quarter ended September 30, 2016 (“Q3 2016 Equity Cure”) was extended from November 23, 2016 to December 16, 2016, and (ii) the total revolving credit exposure (generally defined as funded borrowings plus letters of credit issued and outstanding) was limited to $145.2 million until the Q3 2016 Equity Cure was funded. The Third Amendment stipulated, among other things, that any Excess Cash Balance (generally defined as unrestricted book cash on hand that exceeds $15 million) as of the last business day of each week would be used to temporarily reduce funded borrowings under our Credit Facility.

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On December 9, 2016, we entered into the fourth amendment to the Third A&R Revolving Credit Agreement which stipulated, among other things, that (i) the deadline for funding the Q3 2016 Equity Cure was further extended and (ii) that any

account into which we deposited funds, securities or commodities will be subject to a lien and control agreement for the benefit

of the secured parties under the Third A&R Revolving Credit Agreement.

On December 29, 2016, we entered into the Fifth Amendment which, among other things:

(i) permitted a full waiver for all defaults or events of default arising out of our failure to comply with the financial covenant to maintain a Consolidated Total Leverage Ratio less than 5.00 to 1.00 for the quarter ended September 30, 2016;

(ii) reduced the total aggregate commitments under the Third A&R Revolving Credit Agreement from $200 million to $145 million and reduced the sublimit for letters of credit from $75 million to $50 million. Total aggregate commitments was reduced to $135 million on December 31, 2017, and will be further reduced to $125 million on March 31, 2018, $120 million on June 30, 2018 and $115 million on December 31, 2018 and will also be reduced in an amount equal to the net proceeds of any Permitted Note Indebtedness (as defined in the Fifth Amendment) we may incur in the future;

(iii) modified the borrowings under the Third A&R Revolving Credit Agreement to bear interest at the LIBOR or a base rate plus an applicable margin that cumulatively increases pursuant to the Fifth Amendment by (a) 125 basis points if our Consolidated Total Leverage Ratio is greater than or equal to 5.00 to 1.00, plus (b) 100 basis points if our Consolidated Total Leverage Ratio is greater than or equal to 6.00 to 1.00, plus (c) 100 basis points if our Consolidated Total Leverage Ratio is greater than or equal to 7.00 to 1.00, plus (d) 100 basis points if our Consolidated Total Leverage Ratio is greater than or equal to 8.00 to 1.00. At our election, the 100 basis point increase to the applicable margin upon our Consolidated Total Leverage Ratio being greater than or equal to 8.00 to 1.00 may be replaced with a 150 basis point increase that is payable in kind;

(iv) suspended the Consolidated Total Leverage Ratio and Consolidated Senior Secured Leverage Ratio financial covenants and reduced the Consolidated Interest Coverage Ratio financial covenant requirement from 2.50 to 1.00 to 1.50 to 1.00 for all periods ending on or prior to the Ratio Compliance Date;

(v) requires us to generate Consolidated EBITDA in certain minimum amounts beginning with the quarter ending December 31, 2016 and rolling forward thereafter through the quarter ending December 31, 2018;

(vi) requires us to maintain at least $3 million of Liquidity (as defined therein) as of the last business day of each calendar week;

(vii) restricts our capital expenditures for growth and maintenance to not exceed certain amounts per fiscal year; and

(viii) beginning with the fiscal quarter ending March 31, 2019, our Consolidated Total Leverage Ratio cannot exceed 5.00 to 1.00 and our Consolidated Senior Secured Leverage Ratio cannot exceed 3.50 to 1.00. Until such time as our Consolidated Total Leverage Ratio is less than 5.00 to 1.00, we will also be restricted from making cash distributions to our unitholders and from entering into acquisition or merger agreements with third-party businesses involving a purchase price greater than $10 million, unless such acquisition is funded entirely using the proceeds from the issuance of equity. In addition, until such time as our Consolidated Total Leverage Ratio is less than or equal to 5.00 to 1.00, we will be required to repay any outstanding borrowings under the Credit Facility in an amount equal to 50% of our Excess Cash Flow (as defined in the Fifth Amendment). Our Consolidated Total Leverage Ratio was 8.14 to 1.00 as of December 31, 2017.

On January 7, 2016, in response to our need for additional liquidity, we issued at par Senior Unsecured PIK Notes in the aggregate principal amount of $14 million (the "PIK Notes") to affiliates of EIG and Tailwater, with interest at a rate of 7% due January 7, 2017. Contemporaneous with the resolution of Holdings’ bankruptcy proceedings in April 2016, the PIK Notes and the related PIK interest of $0.3 million were repaid in full.

Term Loan Agreement

The Term Loan Agreement is a $450 million senior secured term loan facility maturing on August 4, 2021. Borrowings under our Term Loan Agreement bear interest at LIBOR plus 4.25% or a base rate as defined in the respective credit agreement

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with a LIBOR floor of 1.00%. The facility will amortize in equal quarterly installments in an aggregate amount equal to 1% of the original principal amount, less any mandatory prepayments (as defined in the Term Loan Agreement), $1.064 million, with the remainder due on the maturity date.

Deferred Financing Costs

Deferred financing costs are capitalized and amortized as interest expense under the effective interest method over the term of the related debt. The unamortized balance of deferred financing costs is included in long-term debt in the balance sheet. Changes in deferred financing costs are as follows (in thousands):



	Year Ended December 31,
	2017			2016
Deferred financing costs, January 1	$	11,474		$	14,141
Capitalization of deferred financing costs	84			1,366
Write-off of deferred financing costs	—			(1,006		)
Amortization of deferred financing costs	(3,263		)	(3,027		)
Deferred financing costs, December 31	$	8,295		$	11,474

7. COMMITMENTS AND CONTINGENT LIABILITIES

Legal Matters

From time to time, we are party to certain legal or administrative proceedings that arise in the ordinary course and are

incidental to our business. For example, during periods when we are expanding our operations through the development of new

pipelines or the construction of new plants, we may become involved in disputes with landowners that are in close proximity to

our activities. While we are involved currently 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.

TPL. On April 5, 2017, TPL SouthTex Processing Company, LP (“TPL”), an indirect subsidiary of Targa, filed a Demand for Arbitration with the American Arbitration Association, against FL Rich Gas Services, LP, an indirect subsidiary of the Partnership (“FL Rich”), related to the operation of T2 EF Cogeneration Holdings LLC (“T2 Cogen”). T2 Cogen, the owner of a cogeneration facility in South Texas, is operated by FL Rich pursuant to the terms of the Generation Plant Operating Agreement, dated March 4, 2013 (the “Operating Agreement”). TPL alleges that FL Rich (i) breached the Operating Agreement in its alleged failure to receive from the United States Environmental Protection Agency a Prevention of Significant Deterioration permit thereby harming Targa’s investment in T2 Cogen, (ii) breached its fiduciary duties with respect to funds or assets of T2 Cogen as operator of T2 Cogen under the terms of the Operating Agreement, and (iii) breached the Operating Agreement and the Limited Liability Company Agreement of T2 Cogen (the “LLC Agreement”) in installing a third turbine inside its Lone Star plant. TPL is seeking, among other things, (a) unspecified damages related to the alleged breaches under the Operating Agreement and the LLC Agreement, (b) the return of approximately $26 million in capital contributions to T2 Cogen received from TPL under the LLC Agreement and the Operating Agreement, and (c) the dissolution and liquidation of T2 Cogen and its assets, respectively. An arbitration hearing has been scheduled for August 2018. We believe this matter is without merit and we intend to defend the arbitration vigorously. Because this matter is in an early stage, we are unable to predict its outcome and the possible loss or range of loss, if any, associated with its resolution or any potential effect the matter may have on our financial position. Depending on the outcome or resolution of this matter, it could have a material effect on our financial position.

Woodsboro. Our General Partner has been named as a defendant in a lawsuit filed on April 29, 2016 in Duval County, Texas styled Victor Henneke, Jr., et al. v. Southcross Energy Partners GP, LLC, et al., Cause No. DC-16-139, 229th Judicial District, Duval County, Texas (the “Henneke Case”). The Henneke Case involves claims by two employees of a third party contractor for personal injury and wrongful death resulting from the alleged negligence of the Partnership related to a pipeline construction project located at our Woodsboro processing facility. The Partnership’s insurance carriers are providing coverage to the Partnership under its general liability policy. No trial date has been set for the contractual liability claims in the case. A jury trial for the personal injury claims began in Duval County, Texas on September 18, 2017. On September 22, 2017, two different award amounts were determined by the jury, the first of which was determined prior to the jury being released by the

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judge and the second was determined after the jury was recalled by the judge. The judge ultimately elected not to enter either jury verdict and a new trial was ordered by the court on September 29, 2017. The successor judge has postponed until April 2018 a hearing on the motion for new trial. We believe that we have adequate insurance to cover this matter.

The five actions filed in the United States District Court for the Northern District of Texas are captioned as follows:


•	Robinson Iglesias v. Southcross Energy Partners, L.P., Southcross Energy Partners GP, LLC, Southcross Holdings LP, Southcross Holdings GP LLC, Bruce A. Williamson, David W. Biegler, Andrew A. Cameron, Nicholas J. Caruso, Jason H. Downie, Wallace Henderson, Jerry W. Pinkerton, Cherokee Merger Sub LLC, and American Midstream Partners, LP, Civil Action No. 3:18-cv-00158-N.


•	Anthony Franchi v. Southcross Energy Partners, L.P., Southcross Energy Partners GP, LLC, Bruce A. Williamson, David W. Biegler, Andrew A. Cameron, Nicholas J. Caruso, Jr., Jason H. Downie, Jerry W. Pinkerton, Randall S. Wade, American Midstream Partners, LP, American Midstream Partners GP, LLC, and Cherokee Merger Sub LLC, Civil Action No. 3:18-cv-00179-D.


•	Adrian Marshall v. Southcross Energy Partners, L.P., Southcross Energy Partners GP, LLC, Southcross Holdings LP, Southcross Holdings GP LLC, Bruce A. Williamson, David W. Biegler, Andrew A. Cameron, Nicholas J. Caruso, Jr., Jason H. Downie, Jerry W. Pinkerton, Randall S. Wade, Bret M. Allan, AmericanMidstream Partners, LP, and Cherokee Merger Sub LLC, Civil Action No. 3:18-cv-00272-D.


•	Kristin Doller v. Southcross Energy Partners, L.P., Southcross Energy Partners GP, LLC, Southcross Holdings LP, Southcross Holdings GP LLC, David W. Biegler, Andrew A. Cameron, Nicholas J. Caruso, Jr., Jason H. Downie, Jerry W. Pinkerton, Randall S. Wade, and Bruce A. Williamson, Civil Action No. 3:18-cv-00291-N.


•	Robert Johnson v. Southcross Energy Partners, L.P., Southcross Energy Partners GP, LLC, Southcross Holdings LP, Southcross Holdings GP LLC, Bruce A. Williamson, David W. Biegler, Andrew A. Cameron, Nicholas J. Caruso, Jr., Jason H. Downie, Jerry W. Pinkerton, Randall S. Wade, Civil Action No. 3:18-cv-00289-C

All defendants deny any wrongdoing in connection with the proposed Transaction and plan to defend rigorously against all pending claims.

Corpus Christi Alumina LLC v. Southcross Marketing Co. Ltd. (In re Sherwin Alumina Co., LLC), Case No. 18-02024 (Bankr. S.D. Tex.) Corpus Christi Alumina LLC the assignee of Sherwin Alumina Company LLC is seeking to recover from our subsidiary Southcross Marketing Co. Ltd., up to $10 million for natural gas payments made to us prior to Sherwin’s 2016 bankruptcy. We believe this claim to be without merit and intend to vigorously defend this claim and do not believe this to have a material effect on our financial position.

Regulatory Compliance

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

Leases

Capital Leases

We have vehicle leases that are classified as capital leases. The termination dates of the lease agreements vary from 2017 to 2019. We recorded amortization expense related to the capital leases of $0.6 million and $0.4 million for the years ended December 31, 2017 and 2016, respectively. Capital leases entered into during the years ended December 31, 2017 and 2016 were $0.5 million and $0.4 million. The capital lease obligation amounts included in the balance sheets were as follows (in thousands):

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	December 31, 2017		December 31, 2016
Other current liabilities	$	410	$	396
Other non-current liabilities	410		497
Total	$	820	$	893

Operating Leases

We maintain operating leases in the ordinary course of our business activities. These leases include those for office and other operating facilities and equipment. The termination dates of the lease agreements vary from 2018 to 2025. Expenses associated with operating leases, recorded in operations and maintenance expenses and general and administrative expenses in our statements of operations, were $5.8 million for the years ended December 31, 2017 and 2016, respectively. A rental reimbursement included in our lease agreement associated with the office space we leased in June 2015 of $2.1 million, net of amortization, has been recorded as a deferred liability in our consolidated balance sheets as of December 31, 2017. This amount will continue to be amortized against the lease payments over the length of the lease term.

Future Minimum Lease Payments

Future minimum annual rental commitments under our capital and operating leases at December 31, 2017 were as follows (in thousands):



Years Ending December 31,	Capital Leases			Operating Leases
2018	$	410		$	3,409
2019	274			2,912
2020	124			1,148
2021	12			922
2022	—			941
Thereafter	—			2,909
Total future payments	820			$	12,241
Less: Imputed interest	$	(20	)
Future lease payments	$	800

8. TRANSACTIONS WITH RELATED PARTIES

Affiliated Directors

The board of directors of our General Partner is comprised of two directors designated by EIG (one of which must be

independent), two directors designated by Tailwater (one of which must be independent), two directors designated by the

Lenders (one of which must be independent) and one director by majority. Our non-employee directors are reimbursed for

certain expenses incurred for their services to us. The director services fees and expenses are included in general and

administrative expenses in our statements of operations. We incurred fees and expenses related to the services from our

affiliated directors as follows (in thousands):



	Year Ended December 31,
	2017		2016
Charlesbank Capital Partners, LLC ⁽¹⁾	$	—	$	97
EIG	165		62
Tailwater	170		61
Total fees and expenses paid for director services to affiliated entities	$	335	$	220


(1)	Charlesbank Capital Partners, LLC indirectly owned approximately one-third of Holdings until April 13, 2016.

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Southcross Energy Partners GP, LLC (our General Partner)

Our General Partner does not receive a management fee or other compensation for its management of us. However, our

General Partner and its affiliates are entitled to reimbursements for all expenses incurred on our behalf, including, among other

items, compensation expense for all employees required to manage and operate our business. We incurred expenses related to

these reimbursements as follows (in thousands):



	Year Ended December 31,
	2017		2016
Reimbursements included in general and administrative expenses	$	11,176	$	11,894
Reimbursements included in operations and maintenance expenses	16,057		20,872
Total reimbursements to our General Partner and its affiliates	$	27,233	$	32,766

Other Transactions with Affiliates

On March 17, 2016, our General Partner entered into retention agreements with certain executives of our General Partner, pursuant to which the executives received a one-time special restructuring bonus in an amount equal to 100% of then-current annual salary for remaining employed with our General Partner through the date of Holdings’ emergence from bankruptcy. The bonuses of $1.5 million were paid by Holdings on April 22, 2016.

In addition, on November 3, 2016, each of these executives of our General Partner received a one-time retention bonus in an amount equal to 100% of then-current annual salary for remaining employed with our General Partner through November 1, 2016. The bonuses of $1.5 million were paid by Holdings.

On January 7, 2016, in response to our need for additional liquidity, we issued the PIK Notes to affiliates of EIG and Tailwater, with interest at a rate of 7% due January 7, 2017. Contemporaneous with the resolution of Holdings’ bankruptcy proceedings in April 2016, the PIK Notes and the related PIK interest of $0.3 million were repaid in full.

We have a gas gathering and processing agreement (the “G&P Agreement”) and an NGL sales agreement (the “NGL Agreement”) with an affiliate of Holdings. Under the terms of these commercial agreements, we transport, process and sell rich natural gas for the affiliate of Holdings in return for agreed-upon fixed fees, and we can sell natural gas liquids that we own to Holdings at agreed-upon fixed prices. The NGL Agreement also permits us to utilize Holdings’ fractionation services at market-based rates. We had purchases of NGLs from Holdings of $1.7 million and $10.0 million for the years ended December 31, 2017 and 2016, respectively.

We have a series of commercial agreements with affiliates of Holdings including a gas gathering and treating agreement, a compression services agreement, a repair and maintenance agreement and an NGL transportation agreement. Under the terms of these commercial agreements, we gather, treat, transport, compress and redeliver natural gas for the affiliates of Holdings in return for agreed-upon fixed fees. In addition, under the NGL transportation agreement, we transport a minimum volume of NGLs per day at a fixed rate per gallon. The operational expense associated with such agreements was capped at $1.7 million per quarter through December 31, 2016. In the first and second quarters of 2016, we exceeded this cap by $1.0 million and $1.4 million, respectively.

We recorded revenues from affiliates of $195.7 million and $97.5 million for the years ended December 31, 2017 and 2016, respectively, in accordance with the G&P Agreement, the NGL Agreement and the series of commercial agreements.

We had accounts receivable due from affiliates of $33.2 million and $8.0 million as of December 31, 2017 and 2016, respectively, and accounts payable due to affiliates of $0.4 million and $0.5 million as of December 31, 2017 and 2016, respectively. The affiliate receivable and payable balances are related primarily to transactions associated with Holdings, noted above, and our joint venture investments (defined in Note 12). The receivable balance due from Holdings is current as of December 31, 2017.

See Note 9 for our issuance of common units to Holdings.

In connection with the execution of the Fifth Amendment, on December 29, 2016, the Partnership entered into (i) the

Investment Agreement with Holdings and Wells Fargo Bank, N.A., (ii) the Backstop Agreement with Holdings, Wells Fargo

Bank, N.A. and the Sponsors and (iii) the Equity Cure Contribution Amendment with Holdings. See Notes 1 and 5 for

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additional details.

9. PARTNERS' CAPITAL

Ownership

Our units outstanding as of December 31, 2017 are as follows (in units):



	Partners’ Capital

		Owned By Parent

	Public	Holdings	Class B		General
	Common	Common	Convertible	Subordinated	Partner
Units outstanding as of December 31, 2015	21,804,219	6,616,400	15,958,990	12,213,713	1,154,965
Vesting of LTIP units, net	205,797	—	—	—	—
In-kind distributions and issuances to general partner to maintain 2.0% ownership	—	—	1,146,885	—	433,233
Common unit issuances to Holdings related to equity cures	—	19,875,674	—	—	—
Units outstanding as of December 31, 2016	22,010,016	26,492,074	17,105,875	12,213,713	1,588,198
Vesting of LTIP units, net	112,097	—	—	—	—
In-kind distributions and issuances to general partner to maintain 2.0% ownership	—	—	1,229,306	—	27,375
Units outstanding as of December 31, 2017	22,122,113	26,492,074	18,335,181	12,213,713	1,615,573

Common units

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

In accordance with the requirements of the Equity Cure Agreement, Holdings was issued 8,029,729 common units on May 2, 2016 for the fourth quarter 2015 equity cure of $11.9 million and 359,459 common units on May 13, 2016 for the first quarter 2016 equity cure of $0.5 million.

Pursuant to the Equity Cure Contribution Amendment, Holdings contributed $17.0 million to the Partnership in exchange for 11,486,486 common units on December 29, 2016. The proceeds of the $17.0 million contribution were used to pay down the outstanding balance under the Third A&R Revolving Credit Agreement and for general corporate purposes.

Class B Convertible Units

As of December 31, 2017, the Class B Convertible Units consist of 18,335,181 units, inclusive of any Class B PIK Units issued. The Class B Convertible Units have the same rights, preferences and privileges, and are subject to the same duties and obligations, as our common units, with certain exceptions as noted below.

Our Partnership Agreement does not allow additional Class B Convertible Units (other than Class B PIK Units) to be issued without the prior approval of our General Partner and the holders of a majority of the outstanding Class B Convertible Units. As of December 31, 2017, all of our outstanding Class B Convertible Units were indirectly owned by Holdings.

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

On February 14, 2017, we issued 299,375 Class B Convertible Units to Holdings and 6,109 general partner units to our General Partner for the quarter ended December 31, 2016. On May 11, 2017, we issued 304,615 Class B Convertible Units to

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Holdings and 6,216 general partner units to our General Partner related to the quarter ended March 31, 2017, which were not previously issued. On August 11, 2017, we issued 309,946 Class B Convertible Units to Holdings and 6,325 general partner units to our General Partner related to the quarter ended June 30, 2017. On November 11, 2017, we issued 315,370 Class B Convertible Units to Holdings and 6,436 general partner units to our General Partner related to the quarter ended September 30, 2017. On February 9, 2018, we issued 320,890 Class B Convertible Units to Holdings and 6,549 general partner units to our General Partner for the quarter ended December 31, 2017.

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

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

Subordinated units

Subordinated units represent limited partner interests in us and convert to common units at the end of the Subordination

Period (as defined in our Partnership Agreement). The principal difference between our common units and our subordinated

units is that in any quarter during the Subordination Period, holders of the subordinated units are not entitled to receive any

distribution of available cash until the common units have received the minimum quarterly distribution plus any arrearages in

the payment of the minimum quarterly distribution from prior quarters. Subordinated units do not accrue arrearages. Beginning

with the third quarter of 2014, until such time we have a Distributable Cash Flow Ratio of at least 1.0, Holdings, the indirect

holder of the subordinated units, has waived the right to receive distributions on any subordinated units that would cause the

Distributable Cash Flow Ratio to be less than 1.0. In addition, the Fifth Amendment imposed additional restrictions on our ability to declare and pay quarterly cash distributions with respect to our subordinated units. See Note 6.

General Partner Interests

As defined by the Partnership Agreement, general partner units are not considered to be units (common or subordinated), but are representative of our general partner's 2.0% ownership interest in us. Our General Partner has received general partner unit PIK distributions in connection with the Class B Convertible Units. In connection with other equity issuances, our General Partner has made capital contributions in exchange for additional general partner units to maintain its 2.0% ownership interest in us. In connection with the 8,029,729 common units issued to Holdings on May 2, 2016 and the 359,459 common units issued to Holdings on May 13, 2016, our General Partner made capital contributions in exchange for 171,209 general partner units to maintain its 2.0% ownership interest in us. In connection with the 11,486,486 common units issued to Holdings on December 29, 2016, we received cash from our General Partner in exchange for 234,419 general partner units to maintain its 2.0% ownership interest in us.

10. INCENTIVE COMPENSATION

Unit Based Compensation

Long-Term Incentive Plan

The 2012 Long-Term Incentive Plan ("LTIP") provides incentive awards to eligible officers, employees and directors of our General Partner. Awards granted to employees under the LTIP generally vest over a three year period in equal annual installments, or in the event of a change in control, in either a common unit or an amount of cash equal to the fair market value of a common unit at the time of vesting, as determined by our management at its discretion. These awards also include distribution equivalent rights that grant the holder the right to receive an amount equal to the cash distributions on common units during the period the award remains outstanding.

On November 9, 2015, the holders of a majority of our limited partner interests approved an amendment to the LTIP which increased the number of common units that may be granted as awards by 4,500,000 units. The term of the LTIP also was extended to a period of 10 years following the amendment's adoption.

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The following table summarizes information regarding awards of units granted under the LTIP:



	Units		Weighted-Average Fair Value at Grant Date
Unvested - December 31, 2015	687,920		$	15.56
Granted units	47,500		3.56
Forfeited units	(73,493	)	15.35
Units recaptured for tax withholdings ⁽¹⁾	(87,849	)	16.42
Vested Units ⁽¹⁾	(205,797	)	15.92
Unvested - December 31, 2016	368,281		$	14.91
Forfeited units	(109,336	)	$	13.47
Units recaptured for tax withholdings⁽¹⁾	(48,752	)	$	14.27
Vested Units ⁽¹⁾	(112,097	)	$	13.93
Unvested - December 31, 2017	98,096		$	10.95


(1)	The weighted-average fair value price on the date of vesting for our vested units was $2.63 and $1.57 for the years ended December 31, 2017 and 2016. The weighted-average fair value price on the date of vesting for our units recaptured for tax withholdings was $2.68 and $1.52 for the years ended December 31, 2017 and 2016.

For the year ended December 31, 2017, we did not grant any equity awards under the LTIP. For the year ended December 31, 2016, we granted awards under the LTIP, with an aggregate grant date fair value of $0.2 million which we have classified as equity awards. As of December 31, 2017 and 2016, we had total unamortized compensation expense of $0.3 million and $3.1 million related to unvested awards. Compensation expense associated with awards is expected to be recognized over the three-year vesting period from each equity award's grant date. As of December 31, 2017 and 2016, we had 5,330,004 and 5,171,916 units, respectively, available for issuance under the LTIP.

Unit Based Compensation Expense

The following table summarizes information regarding recognized compensation expense, which is included in general and administrative and operations and maintenance expense in our statements of operations (in thousands):



	Year Ended December 31,
	2017		2016
Unit-based compensation	$	1,375	$	3,523

Employee Savings Plan

We have employee savings plans under Sections 401(a) and 401(k) of the Internal Revenue Code of 1986, as amended, whereby employees of our General Partner may contribute a portion of their base compensation to the employee savings plan, subject to limits. We provide a matching contribution each payroll period equal to 100% of the employee's contribution up to the lesser of 6% of the employee's eligible compensation or $16,200 annually for the period. The following table summarizes information regarding contributions and the expense recognized for the matching contributions, which is included in operating and maintenance expense and general and administrative expense in our statements of operations (in thousands):



	Year Ended December 31,
	2017		2016
Matching contributions expensed for employee savings plan	$	731	$	1,252

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11. REVENUES

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



	Year Ended December 31,
	2017		2016
Sales of natural gas	$	379,423	$	271,302
Sales of NGLs and condensate	179,247		158,968
Transportation, gathering and processing fees	103,669		113,482
Other ⁽¹⁾	3,610		4,971
Total revenues	$	665,949	$	548,723

(1) Other revenue for the year ended December 31, 2017 includes $1.1 million of business interruption insurance proceeds related to the outage at Holdings’ Lancaster gas treating facility in February 2016.

12. INVESTMENTS IN JOINT VENTURES

We own equity interests in three joint ventures with Targa as our joint venture partner. T2 Eagle Ford Gathering Company LLC (“T2 Eagle Ford”), T2 LaSalle Gathering Company LLC (“T2 LaSalle”) and T2 Cogen 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. 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. Our maximum exposure to loss related to these joint ventures includes our equity investment, any additional capital contributions and our share of any operating expenses incurred by the joint ventures.

We evaluate investments in joint ventures for impairment when factors indicate that a decrease in the value of the investment has occurred that is not temporary. During the fourth quarter of 2016, as part of firm wide cost-saving initiatives, management decided to significantly reduce the utilization of the T2 Cogen facility. In the immediate future, the T2 Cogen facility will be utilized only as a swing or backup facility for our Lone Star processing facility ("LS1"). As volumes are expected to increase in the ensuing years, management expects to need the generation capacity from the T2 Cogeneration facility to provide power to its LS1 facility. As the LS1 facility represents a more economical option to provide electricity to the Lone Star processing plant, management’s decision to reduce the utilization of the T2 Cogen substantially and as the electricity sales to FL Rich Gas Services represents the only source of revenue for T2 Cogen, the reduction in utilization significantly reduces the operating income associated with these assets. As a result in this change in the use of the T2 Cogen assets, T2 Cogen tested such assets for impairment, and recorded a $13.3 million impairment during the fourth quarter of 2016. We recorded our proportionate share 50% of such impairment within equity in losses of joint venture investments.

The joint ventures’ summarized financial data from their statements of operations for the years ended December 31, 2017 and 2016 is as follows (in thousands):



	Year Ended December 31,
	2017			2016
Revenue
T2 Eagle Ford	$	4,319		$	5,667
T2 Cogen	421			2,556
T2 LaSalle	1,619			1,963

Net loss
T2 Eagle Ford	$	(19,454	)	$	(19,312	)
T2 Cogen	(3,730		)	(19,998		)
T2 LaSalle	(5,872		)	(5,872		)

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Our equity in losses of joint venture investments is comprised of the following for the years ended December 31, 2017 and 2016 (in thousands):



	Year Ended December 31,
	2017			2016
T2 Eagle Ford	$	(9,727	)	$	(9,656	)
T2 Cogen	(1,865		)	(9,999		)
T2 LaSalle	(1,468		)	(1,468		)
Equity in losses of joint venture investments	$	(13,060	)	$	(21,123	)

Our investments in joint ventures is comprised of the following as of December 31, 2017 and 2016 (in thousands):



	December 31, 2017		December 31, 2016
T2 Eagle Ford	$	92,248	$	101,669
T2 Cogen	4,425		6,003
T2 LaSalle	15,074		16,424
Investments in joint ventures	$	111,747	$	124,096

The joint ventures’ summarized balance sheets as of December 31, 2017 and 2016 is as follows (in thousands):



	December 31, 2017		December 31, 2016
T2 Cogen
Current assets	$	517	$	603
Property, plant and equipment, net	8,746		12,000
Total assets	9,263		12,603
Total liabilities	414		596
Total equity	8,849		12,006
Total liabilities and equity	$	9,263	$	12,603

T2 Eagle Ford
Current assets	$	2,150	$	2,517
Property, plant and equipment, net	185,399		203,810
Total assets	187,549		206,327
Total liabilities	2,146		2,173
Total equity	185,403		204,154
Total liabilities and equity	$	187,549	$	206,327

T2 LaSalle
Current assets	$	801	$	1,046
Property, plant and equipment, net	60,583		66,028
Total assets	61,384		67,074
Total liabilities	971		1,262
Total equity	60,413		65,812
Total liabilities and equity	$	61,384	$	67,074

13. CONCENTRATION OF CREDIT RISK

Our primary markets are in South Texas, Alabama and Mississippi. We have a concentration of revenues and trade

accounts receivable due from customers engaged in the production, trading, distribution and marketing of natural gas and NGL

products. These concentrations of customers may affect overall credit risk in that these customers may be affected similarly by

changes in economic, regulatory or other factors. We analyze our customers’ historical financial and operational information

before extending credit.

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Our top ten customers, excluding affiliates, for the years ended December 31, 2017 and 2016 represent the following percentages of consolidated revenue:

The percentage of total consolidated revenue for each customer, excluding affiliates, that exceeded 10% of total revenues for the years ended December 31, 2017 and 2016 was as follows:



	Year Ended December 31,
	2017	2016
Trafigura AG	(a)	10.7	%

(a) Information is not provided for periods for which the customer or producer was less than 10% of our consolidated revenue.

For the years ended December 31, 2017 and 2016, we did not experience significant nonpayment for services. We had no allowance for uncollectible accounts receivable at December 31, 2017. We recorded an allowance for uncollectible accounts receivable of $0.1 million at December, 31, 2015, which was written off in 2016.

14. SUBSEQUENT EVENTS

On January 22, 2018, in connection with the Investment Agreement and Backstop Agreement, the Sponsors provided us $15.0 million in exchange for the Investment Notes. See Note 2 to the consolidated financial statements.

15. SUPPLEMENTAL INFORMATION

Supplemental Cash Flow Information (in thousands)



	Year Ended December 31,
	2017		2016
Supplemental Disclosures:
Cash paid for interest	$	35,142	$	32,459
Cash received for taxes	4		52
Supplemental schedule of non-cash investing and financing activities:
Accounts payable related to capital expenditures	1,042		3,186
Capital lease obligations	140		423
Accrued distribution equivalent rights on the LTIP units	—		11
Class B Convertible unit in-kind distributions	3,188		2,307
Common unit issuances to General Partner related to equity cures and equity contributions	—		854

Capitalization of Interest Cost

We capitalize interest on projects during their construction period. Once a project is placed in service, capitalized interest, as a component of the total cost of the construction, is depreciated over the estimated useful life of the asset constructed. We incurred the following interest costs (in thousands):



	Year Ended December 31,
	2017			2016
Total interest costs	$	38,723		$	36,066
Capitalized interest included in property, plant and equipment, net	(542		)	(900		)
Interest expense	$	38,181		$	35,166

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Southcross Assets Considered Leases to Third Parties

We have pipelines that transport natural gas to two power plants in Nueces County, Texas under fixed-fee contracts. The contracts have a primary term through 2029 and an option to extend the agreement by an additional term of up to ten years. These contracts are considered operating leases under the applicable accounting guidance.

Future minimum annual demand payment receipts under these agreements as of December 31, 2017 were as follows: $2.2 million in 2018; $2.2 million in 2019; $2.2 million in 2020; $1.5 million in 2021; $1.5 million in 2022 and $10.2 million thereafter. The revenue for the demand payments is recognized on a straight-line basis over the term of the contract. The demand fee revenues under the contracts were each $2.6 million for the years ended December 31, 2017 and 2016, respectively, and have been included within transportation, gathering and processing fees within Note 11. These amounts do not include variable fees based on the actual gas volumes delivered under the contracts. Variable fees recognized in revenues within transportation, gathering and processing fees within Note 11 were $1.0 million and $3.0 million for the years ended December 31, 2017 and 2016, respectively. Deferred revenue associated with these agreements was $11.6 million and $8.5 million at December 31, 2017 and 2016, respectively.


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

None.


Item 9A.	Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Under the direction of our general partner’s Chief Executive Officer and Chief Financial Officer, we evaluated our disclosure controls and procedures and concluded that our disclosure controls and procedures were effective as of December 31, 2017.

Management’s Report on Internal Control Over Financial Reporting

Our General Partner's management is responsible for establishing and maintaining adequate internal control over our financial reporting. With our participation, an evaluation of the effectiveness of our internal control over financial reporting was conducted as of December 31, 2017, based on the framework and criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Based on this evaluation, our General Partner’s management has concluded that our internal control over financial reporting was effective as of December 31, 2017.

This Form 10-K does not include an attestation report of our independent registered public accounting firm on internal control over financial reporting as a smaller reporting company. As defined in Rule 12b-2 of the Exchange Act, we meet the criteria to be a smaller reporting company and have elected to use the reporting exemptions of a smaller reporting company in connection with the preparation of the consolidated financial statements as of December 31, 2017. Pursuant to the smaller reporting company requirements we are not required to to include an attestation report of our independent registered public accounting firm on internal control over financial reporting.

Changes in Internal Control

No change in internal control over financial reporting occurred during the quarter ended December 31, 2017, that has materially affected, or is reasonably likely to affect materially, our internal control over financial reporting.


Item 9B.	Other Information

None.

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PART III


Item 10.	Directors, Executive Officers and Corporate Governance

Management of Southcross Energy Partners, L.P.

Southcross Energy Partners, L.P. is managed by the directors and executive officers of our General Partner. Our General Partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. Holdings owns 100% of our General Partner. Our General Partner has a board of directors, and our unitholders are not entitled to elect the directors or to directly or indirectly participate in our management or operations. Our General Partner will be liable, as the General Partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our General Partner.

Director Independence

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

Committees of the Board of Directors

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

Conflicts Committee

Andrew A. Cameron, Nicholas J. Caruso, and Jerry W. Pinkerton serve as the members of our Conflicts Committee. Mr. Pinkerton serves as the chairman of the Conflicts Committee. Our Partnership Agreement provides that the Conflicts Committee, as delegated by the board of directors of our General Partner as circumstances warrant, will review conflicts of interest between us and our General Partner or between us and affiliates of our General Partner. If a matter is submitted to the Conflicts Committee for its review and approval, the Conflicts Committee will determine if the resolution of a conflict of interest that has been presented to it by the board of directors of our General Partner is fair and reasonable to us. The current members of the Conflicts Committee and any future members may not be officers or employees of our General Partner, directors, officers or employees of our General Partner's affiliates or a holder of any ownership interest in our General Partner, its affiliates or the Partnership, except for common units and certain awards given to directors in their capacity as a director. In addition, they must comply with the independence standards established by the NYSE and the Exchange Act for service on an audit committee of a board of directors. Any matters approved by the Conflicts Committee will be conclusively deemed to have been approved in good faith, to be fair and reasonable to us, approved by all of our partners and not a breach by our General Partner of any duties it may owe us or our unitholders.

Audit Committee

Andrew A. Cameron, Nicholas J. Caruso, and Jerry W. Pinkerton serve as the members of the Audit Committee. Mr. Pinkerton serves as the chairman of the Audit Committee. The Audit Committee oversees, reviews, acts on and reports on various auditing and accounting matters to the board of directors of our General Partner, including: (i) the selection of our independent accountants, (ii) the scope of our annual audits, (iii) fees to be paid to the independent accountants, (iv) the performance of our independent accountants, (v) the review of our internal controls process and (vi) our accounting practices. In addition, the Audit Committee oversees our compliance programs relating to legal and regulatory requirements. Messrs. Cameron, Caruso and Pinkerton comply with the independence and experience standards established by the NYSE and the Exchange Act for service on an audit committee of a board of directors. Our General Partner is generally required to have at least three independent directors serving on its board of directors at all times. Messrs. Cameron, Caruso and Pinkerton are each audit committee financial experts.

Compensation Committee

Andrew A. Cameron, Nicholas J. Caruso, and Jason H. Downie serve as members of the Compensation Committee. Mr. Downie serves as chairman of the Compensation Committee. The Compensation Committee establishes salaries, incentive compensation and other forms of compensation for officers, non-employee directors and other employees, as well as administers our incentive compensation and benefit plans.

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Directors and Executive Officers

Directors are appointed for a term of one year and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the discretion of the board of directors. The following table shows information for the directors and executive officers of our General Partner.



Name	Age	Position with Southcross Energy Partners GP, LLC
Bruce A. Williamson	58	Chairman, President and Chief Executive Officer
Bret M. Allan(1)	49	Senior Vice President, Chief Financial Officer and Principal Accounting Officer
Joel D. Moxley(1)	59	Senior Vice President and Chief Commercial Officer
Kelly J. Jameson(1)	53	Senior Vice President, General Counsel and Corporate Secretary
David W. Biegler(1)	71	Director
Andrew A. Cameron	58	Director
Nicholas J. Caruso	72	Director
Jason H. Downie(1)	47	Director
Randall S. Wade	47	Director
Jerry W. Pinkerton	77	Director

(1)

These directors and executive officers served as directors or executive officers of Southcross Holdings GP LLC ("Holdings GP") on March 28, 2016 when Holdings GP, Holdings and certain of Holdings' subsidiaries filed for bankruptcy. On April 11, 2016, the bankruptcy court confirmed Holdings' plan of reorganization, and on April 13, 2016, Holdings GP, Holdings and Holdings' subsidiaries emerged from bankruptcy.

Bruce A. Williamson

Mr. Williamson was elected as Chairman, President and Chief Executive Officer of our General Partner on January 6, 2017. Mr. Williamson joined the Board of our General Partner in April 2013 and served as an independent director designee of the Sponsors as a result of contractual arrangements. Mr. Williamson previously served as a member of the Audit Committee, Compensation Committee and Conflicts Committee of the Board of our General Partner. In July 2016, Mr. Williamson became the Chairman of the Board of Holdings GP and no longer was an independent director of our General Partner.

Mr. Williamson has over 35 years of experience encompassing all facets of the energy value chain. Most recently, Mr. Williamson was the President and Chief Executive Officer and director of Cleco Corporation (now Cleco Corporate Holdings LLC), an energy services company, from July 2011 to April 2016 and was the Chairman, President and Chief Executive Officer at Dynegy, Inc., an energy services company, from 2002 through 2011. Prior to his role at Dynegy, Inc., Mr. Williamson was the President and Chief Executive Officer at Duke Energy Global Markets. Prior to Duke, Mr. Williamson was Senior Vice President Finance at PanEnergy Corp. and also worked for Shell Oil Company for 14 years in exploration and production in the United States and internationally.

Mr. Williamson also serves on the board of TerraForm Power, Inc. Mr. Williamson received his bachelor's degree in finance from the University of Montana, and his master's in business administration from the University of Houston.

Joel D. Moxley

Joel D. Moxley was appointed Senior Vice President and Chief Commercial Officer of our General Partner in June 2015. Since June 2015, Mr. Moxley has also served as the Senior Vice President and Chief Commercial Officer of Holdings GP.

Before joining our General Partner and Holdings GP, Mr. Moxley served as Senior Vice President of Operations Services for Crestwood Equity Partners LP and Crestwood Midstream Partners LP (collectively, “Crestwood”), both midstream master limited partnerships until May 2015. The two entities were formed in May 2013 and October 2013, respectively, through a merger between Inergy, L.P. and Crestwood Holdings GP, which became collectively Crestwood Equity Partners LP, and a merger between Crestwood Midstream Partners LP and Inergy Midstream, L.P., which became collectively Crestwood Midstream Partners LP. Mr. Moxley’s responsibilities included oversight of a variety of functions including human resources, information technology, operational engineering, supply chain, risk management and safety and regulatory that supported Crestwood. From October 2010 to May 2013, Mr. Moxley was the Chief Operating Officer for Crestwood Holdings GP and Crestwood Midstream Partners LP, where Mr. Moxley was responsible for operations, commercial, engineering, environmental,

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safety, regulatory and supply chain activities. From April 2008 to October 2010, Mr. Moxley was a part of a team that evaluated midstream acquisition opportunities on behalf of a private equity sponsor that ultimately acquired Quicksilver Gas Services LP, a midstream master limited partnership, which was subsequently renamed Crestwood Midstream Partners LP. Prior to joining companies now affiliated with Crestwood, Mr. Moxley was Senior Vice President of Crosstex Energy, L.P. (“Crosstex”) with responsibility for the commercial activities of Crosstex’s South Louisiana gas processing and NGL fractionation assets as well as the marketing of NGLs for Crosstex companywide. Mr. Moxley’s experience also includes midstream leadership roles at Enterprise Products Partners L.P., El Paso Corporation, PG&E Corporation, Valero Energy Corporation and Occidental Petroleum.

Mr. Moxley received a bachelor’s degree in Chemical Engineering from Rice University. He is also a past Chairman of the Gas Processors Association and has served as a board member of the Texas Pipeline Association and the Petrochemical Feedstock Association of the Americas.

Bret M. Allan

Bret M. Allan was appointed Senior Vice President and Chief Financial Officer of our General Partner in June 2015. Effective December 2, 2016, Mr. Allan also assumed the responsibilities of principal accounting officer. Since June 2015, Mr. Allan additionally has served as the Senior Vice President and Chief Financial Officer of Holdings GP.

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

Before joining Regency, Mr. Allan held various managerial positions at Energy Future Holdings and its predecessor company, TXU Corp., including positions in strategic planning, financial analysis and risk. Mr. Allan received a bachelor’s degree in economics from the University of California at Berkeley and holds a master’s degree in business administration with a concentration in finance from the University of Chicago Graduate School of Business.

Kelly J. Jameson

Kelly J. Jameson was appointed Senior Vice President, General Counsel and Corporate Secretary of our General Partner in September 2015. Since September 2015, Mr. Jameson has also served as the Senior Vice President, General Counsel and Corporate Secretary of Holdings GP.

Prior to joining our General Partner and Holdings GP, Mr. Jameson was Associate General Counsel at USA Compression Partners, LP having previously served as Senior Vice President, General Counsel and Corporate Secretary of Crestwood Midstream Partners from 2010 to 2013. Mr. Jameson was employed by TransCanada Corporation from 2007 to 2010, where he was Senior Counsel and Corporate Secretary for the U.S. subsidiaries of TransCanada Corporation. From 1996 to 2007, Mr. Jameson served as Senior Counsel and Assistant Corporate Secretary for El Paso Corporation, and from 1993 to 1996, he served as Vice President and General Counsel for Cornerstone Natural Gas Company, Inc. Mr. Jameson received a bachelor’s degree in business administration from Southern Methodist University and a juris doctor degree from Oklahoma City University. Mr. Jameson is a member of the Texas Bar Association.

David W. Biegler

David W. Biegler served as Chairman of the board of directors of our General Partner from August 2011 to January 6, 2017 and currently serves as a director of our General Partner. Mr. Biegler served as Chairman of the board of directors and Chief Executive Officer of our General Partner from August 2011 to December 2014 and as President of our General Partner from October 2012 to March 2014. From August 2014 to July 2016, Mr. Biegler has also served as the Chairman of the board of directors of Holdings GP, and he served as Chief Executive Officer of Holdings GP from August 2011 through December 2014.

Mr. Biegler has more than 50 years of experience in the energy industry, having held various management positions in upstream, midstream, downstream, electric generation and oilfield services companies. From 2004 until 2012, Mr. Biegler served as chairman and chief executive officer of Estrella Energy LP, an entity formed for the purpose of acquiring midstream companies, which was a founding investor in our predecessor.

From 2002 to 2004, Mr. Biegler was Chairman of the board of Regency Gas Services, a midstream company that he co-founded and that was ultimately sold to a private equity firm. He retired as Vice Chairman of the board of TXU Corp. (now Energy Future Holdings Corp.) in 2001, a position he assumed earlier that year. From 1997 to 2001, Mr. Biegler served as

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President and Chief Operating Officer of TXU Corp., the result of a merger between Texas Utilities and ENSERCH Corp. From 1966 to 1997, he held various management positions at ENSERCH Corp. and its upstream, midstream, downstream and oilfield field services subsidiaries, including as ENSERCH’s Chairman, President and Chief Executive Officer from 1994 to 1997. Mr. Biegler received a bachelor’s degree in physics from St. Mary’s University, San Antonio, and is a graduate of Harvard University’s advanced management program.

Mr. Biegler also serves on the board of Southwest Airlines Co., Trinity Industries, Inc. and Austin Industries. He is a past director of Dynegy, Inc., Guaranty Financial Group and Animal Health International, Inc. He previously served as a member of the National Petroleum Council and as Chairman of the American Gas Association, the Southern Gas Association, the American Gas Foundation and the Texas Pipeline Association.

On August 4, 2014, Southcross Energy LLC, a Delaware limited liability company and the predecessor of the Partnership, and TexStar Midstream Services, LP, a Texas limited partnership, combined pursuant to a Contribution Agreement in which Southcross Holdings LP, a Delaware limited partnership ("Holdings") was formed (the "Holdings Transaction"). In connection with the Holdings Transaction, Mr. Biegler was selected to serve as Chairman for a two year term or until his earlier death or resignation by the majority of the directors of our General Partner, as a result of contractual arrangements. There are no current arrangements with Mr. Biegler.

Andrew A. Cameron

Andrew A. Cameron was elected as an independent member of the board of directors of our General Partner in January 2017. Mr. Cameron serves as a member of the Audit Committee, Conflicts Committee and Compensation Committee of the board of directors of our General Partner. Mr. Cameron has more than 37 years of experience in auditing, internal controls, finance and accounting. He retired as Vice President, Internal Audit and SOX Compliance of Vistra Energy, formerly Energy Future Holdings Corp., an electric utility company, in 2016. During the time Mr. Cameron served as Vice President, Internal Audit and SOX Compliance, Energy Future Holdings Corp. filed for Chapter 11 bankruptcy in April of 2014. Prior to his employment at Energy Future Holdings Corp., Mr. Cameron was Vice President and Controller from 2000 to 2004 at a subsidiary company of TXU Corp., an electric utility company and the predecessor company of Energy Future Holdings Corp., where he served in other finance and accounting roles from 1997 to 2000. Mr. Cameron served in various finance and audit positions with ENSERCH Corporation from 1984 to 1997. Mr. Cameron worked for KPMG from 1979 to 1984. Mr. Cameron has served as a financial consultant for the Dallas Symphony Association since October 2017. Mr. Cameron received a bachelor’s degree in business and administration from the University of Strathclyde, Glasgow, Scotland and is a Certified Public Accountant.

The members of our General Partner appointed Mr. Cameron to serve as a director due to his audit, accounting and financial reporting expertise and knowledge that qualifies him as a financial expert for his role as a member of the Audit Committee.

Nicholas J. Caruso

Nicholas J. Caruso was elected as an independent member of the board of directors of our General Partner in July 2015. Mr. Caruso serves as a member of the Audit Committee, Conflicts Committee and Compensation Committee of the board of directors of our General Partner. Mr. Caruso has more than 45 years of management, finance and accounting experience. He was Executive Vice President and Chief Financial Officer of Dynegy Holdings, Inc. from 2002 through 2005, where he was responsible for the company’s treasury, insurance and audit functions. Prior to Dynegy, Mr. Caruso spent more than 30 years with Shell Oil Company in positions of increasing responsibility until his retirement in 2001. He last served as Shell’s Vice President of Finance and Chief Financial Officer from 1999 to 2002 and worked directly with Shell’s board of directors to implement internal controls and review financial results. Prior to being named CFO of Shell, Mr. Caruso served as its Controller and General Auditor. Mr. Caruso received a bachelor’s degree in accounting from Louisiana State University.

The members of our General Partner appointed Mr. Caruso to serve as a director due to his audit, accounting and financial reporting expertise and knowledge that qualifies him as a financial expert for his role as a member of the Audit Committee.

Jason H. Downie

Jason H. Downie was appointed to the board of directors of our General Partner in August 2014 and serves as Chairman of the Compensation Committee. Since August 2014, Mr. Downie has also served on the board of directors of Holdings GP.

Mr. Downie has more than 20 years of investment experience and co-founded Tailwater Capital, LLC in January 2013. At Tailwater, Mr. Downie’s primary responsibilities include deal sourcing, transaction execution and monitoring of portfolio companies as well as executive leadership of Tailwater. Prior to co-founding Tailwater, Mr. Downie was a partner with HM

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Capital Partners, a private equity firm, from August 2000 to December 2012 and served on its investment committee. He joined HM Capital in August 2000 from Rice Sangalis Toole and Wilson, a mezzanine private equity firm, where he was an associate, from June 1999 until August 2000. Prior to Rice Sangalis Toole and Wilson, Mr. Downie was an associate in the equity trading group with Donaldson, Lufkin & Jenrette and was responsible for energy and transportation. Mr. Downie currently serves as a director of TW SWD & Solids Holdco LP, Pivotal Petroleum Partners LP, TSL Holdings I LP, Align Midstream Partners LP and Petro Waste Environmental. Mr. Downie received a bachelor’s degree and master’s degree in business administration from The University of Texas at Austin.

Mr. Downie serves as the director designee of Tailwater, one of our Sponsors, as a result of contractual arrangements entered into in connection with the Holdings Transaction. In addition to his affiliation with Tailwater, Mr. Downie was selected to serve as a director due to, his knowledge of the energy industry and his financial and business expertise.

Randall S. Wade

Randall S. Wade was appointed to the board of directors of our General Partner in December 2017. Since December 2017, Mr. Wade has also served on the board of directors of Holdings GP.

Mr. Wade has more than 25 years of investment experience. He is currently the Chief Operating Officer for EIG Global Energy Partners, LLC ("EIG") and a member of each of its Investment and Executive Committee. He has primary responsibility for the operations and administration of the firm and its investment vehicles. Since joining EIG in 1996, Mr. Wade has filled various roles including head of EIG’s structured funds, investment principal with coverage responsibility for Australia, and as an analyst for oil and gas investments. Prior to joining EIG, Mr. Wade was a Commercial Lending Officer for First Interstate Bank of Texas, where he was responsible for developing a middle-market loan portfolio. Mr. Wade currently serves as an investment committee member for each of Triloma EIG Global Energy Fund and Triloma EIG Global Energy Term Fund I. He received a bachelor’s degree in economics and a bachelor's degree of business administration in finance from the University of Texas at Austin.

Mr. Wade serves as the director designee of EIG, one of our Sponsors. In addition to his affiliation with EIG, Mr. Wade was selected to serve as a director on the board due to his financial and business expertise.

Jerry W. Pinkerton

Jerry W. Pinkerton was appointed as an independent member of the board of directors of our General Partner in April 2012. In addition, Mr. Pinkerton serves as Chairman of the Audit Committee and Chairman of the Conflicts Committee of the board of directors of our General Partner. With respect to the Audit Committee, Mr. Pinkerton qualifies as an "audit committee financial expert." Mr. Pinkerton has over 55 years of management, finance and accounting experience and has held various positions in several publicly traded companies. Mr. Pinkerton served on the board of directors and a member of the audit committee of the general partner of Holly Energy Partners, L.P., a publicly traded master limited partnership that owns and operates petroleum product and crude oil pipeline and terminal, tankage and loading rack facilities, from July 2004 to June 2017, and as chairman of its audit committee until November 2016. From December 2000 to December 2003, Mr. Pinkerton served as a consultant to TXU Corp. (now Vistra Energy), and, from August 1997 to December 2000, he served as Controller of TXU Corp. and its U.S. subsidiaries. From August 1988 until its merger with TXU Corp. in August 1997, Mr. Pinkerton served as the Vice President and Chief Accounting Officer of ENSERCH Corporation. Prior to joining ENSERCH in August 1988, Mr. Pinkerton was employed for 26 years as an auditor by Deloitte Haskins & Sells, a predecessor firm of Deloitte & Touche, LLP, including 15 years as an audit partner. From May 2008 to June 2011, Mr. Pinkerton also served on the board of directors of Animal Health International, Inc., an animal health distribution company, where he also served as chairman of its audit committee. Mr. Pinkerton received his bachelor’s degree in accounting from The University of North Texas.

Mr. Pinkerton serves as an independent director designee of our Sponsors as a result of contractual arrangements entered into in connection with the Holdings Transaction. He was appointed due to his audit, accounting and financial reporting expertise and knowledge that qualifies him as a financial expert for his role as the chairman of the Audit Committee. Due to his executive managerial experience with public companies and public accounting firms and his prior board service, including audit committee experience, Mr. Pinkerton possesses business and management expertise and a broad range of expertise and knowledge of board committee functions.

Code of Ethics, Corporate Governance Guidelines and Board Committee Charters

Our General Partner has adopted a Code of Business Conduct and Ethics, which applies to our General Partner's directors, officers and employees. A waiver of the Code of Business Conduct and Ethics for any director or executive officer of our General Partner may be granted only by the Audit Committee, and such committee will report any such waiver to the board of directors of our General Partner. A waiver of the Code of Business Conduct and Ethics for other officers or employees may be granted only by our Chief Executive Officer, who will thereafter report any such waiver to the Audit Committee. The board

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of directors of our General Partner has also adopted Corporate Governance Guidelines, which outline the important policies and practices regarding our governance. Jerry W. Pinkerton serves as the lead director, as such term is used in the Corporate Governance Guidelines. The lead director is 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." Interested parties may communicate directly with the independent directors by submitting a communication in an envelope marked “Confidential” addressed to the “Independent Members of the Board of Directors” in care of Mr. Pinkerton at 1717 Main Street, Suite 5200, Dallas, Texas 75201.

We make available free of charge, within the "Investors" section of our website at www.southcrossenergy.com, and in print to any unitholder who so requests, our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Audit Committee Charter and Compensation Committee Charter. Requests for print copies may be directed to investorrelations@southcrossenergy.com or to: Investor Relations, Southcross Energy Partners, L.P., 1717 Main Street, Suite 5200, Dallas, Texas 75201, or telephone (214) 979-3720. We will post on our website all waivers to or amendments of the Code of Business Conduct and Ethics, that are required to be disclosed by applicable law and the NYSE's Corporate Governance Listing Standards. The information contained on, or connected to, our website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.

Section 16(a) Beneficial Ownership Reporting Compliance

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

To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that, all reporting obligations of our General Partner's officers, directors and greater than 10% unitholders under Section 16(a) were satisfied during the year ended December 31, 2017.


Item 11.	Executive Compensation

Executive Compensation Discussion

Overview of our Executive Compensation Program

This executive compensation discussion describes the compensation policies, programs, material components and decisions of the Compensation Committee with respect to our General Partner’s executive officers, including the following individuals who are referred to as our “Named Executive Officers” in 2017:


•	Bruce A. Williamson, Chairman, President and Chief Executive Officer;


•	John E. Bonn, Former President and Chief Executive Officer;


•	Joel D. Moxley, Senior Vice President and Chief Commercial Officer; and


•	Bret M. Allan, Senior Vice President and Chief Financial Officer.

Our General Partner's compensation practices and programs generally are designed to attract, retain and motivate exceptional leaders and structured to align compensation with our overall performance. The compensation practices and programs have been implemented to promote achievement of short-term and long-term business objectives consistent with our strategic plans and are applied to reward performance. To accomplish these objectives, the compensation program in 2017 consisted of the following components: (i) base salary, designed to compensate executive officers for work performed during the fiscal year; (ii) bonus, designed to reward executive officers for performance; (iii) long-term incentive compensation in the form of cash awards, designed to retain our talent and compensate our executive officers, including our Named Executive Officers, for long-term service; and (iv) certain benefits, perquisites, retirement, severance and change in control arrangements.

Our General Partner, under the direction of its board of directors, is responsible for managing our operations and employs all of the employees that operate our business. We reimburse our General Partner, generally on a dollar-for-dollar basis, for the compensation attributable to the work performed on our behalf by its employees. Certain of the employees of our General Partner provide management, administrative, operational and workforce related services to our affiliates, including Holdings, which owns 100% of our General Partner, and is an affiliate of our Sponsors.

Effective January 6, 2017, Mr. Bonn stepped down as President and Chief Executive Officer of our General Partner and Mr. Williamson was elected as Chairman, President and Chief Executive Officer of our General Partner.

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

Role of the Compensation Committee and Management

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

The Compensation Committee has overall responsibility for evaluating and approving the compensation plans, policies and programs of our General Partner. To that end, the Compensation Committee has the responsibility, power and authority to set the compensation of executive officers, determine grant awards under and administer our equity compensation plans, and assume responsibility for all matters related to the foregoing. The Compensation Committee is charged, among other things, with the responsibility of reviewing the executive officer compensation policies and practices for (i) adherence to our compensation philosophy and (ii) ensuring that the total compensation paid to our executive officers is fair, reasonable and competitive. In 2017, these compensation programs for executive officers consisted of base salary and bonus awards, earnings under cash awards under our 2016 Cash-Based Long-Term Incentive Plan, as described below, as well as other customary employment benefits. Total compensation of executive officers and the relative emphasis of our main components of compensation are reviewed at least annually by the Compensation Committee, which then makes recommendations to the board of directors of our General Partner for its approval.

It is the practice of the Compensation Committee to meet in person or by conference call at least once a year to, among other things: (i) assess the performance of the Chief Executive Officer and other executive officers with respect to our results for the preceding year, (ii) establish compensation levels for each executive officer for the ensuing year, (iii) determine the amount of the annual bonus pool approved by the board of directors of our General Partner to be paid to the executive officers, after taking into account both the target bonus levels established for those executive officers at the outset of the preceding year and the foregoing performance factors, (iv) determine cash awards under the 2016 Cash-Based Long-Term Incentive Plan and (v) determine bonus payments to be made in the event of a change in control for executive officers and other key employees. Our Chief Executive Officer participates in the process of allocating our bonus pool and makes recommendations to the Compensation Committee regarding the amount of bonuses and other compensation paid to executive officers, other than to the Chief Executive Officer.

Compensation Components and Analysis

Base Salary. None of our Named Executive Officers received an increase in their base salary in 2017. Base salaries for our Named Executive Officers are reviewed periodically by the Compensation Committee, with adjustment expected to be made generally in accordance with the considerations described above and to maintain base salaries at competitive levels.

Annual Performance-Based Compensation. Each of our Named Executive Officers is eligible to participate in an incentive bonus compensation program under which incentive awards are determined annually. For 2017, the board of directors of our General Partner granted bonuses to Joel Moxley and Bret Allan in the amount of $297,750 and 247,500, respectively.

Long-Term Equity Participation. Please see the sections following our Summary Compensation Table (as defined below) for discussion regarding the long-term equity compensation granted to our Named Executive Officers.

Long-Term Cash Incentive. Please see the sections following our Summary Compensation Table for discussion regarding the long-term cash compensation granted to our Named Executive Officers.

Benefit Plans, Perquisites and Retirement. We provide our executive officers, including our Named Executive Officers, with a standard complement of health and retirement benefits under the same plans as all other employees, including medical, dental and vision benefits, disability and life insurance coverage, and a defined contribution plan that is tax-qualified under Section 401(k) of the Internal Revenue Code (the “401(k) Plan”). We believe that our health benefits provide stability to our Named Executive Officers, thus enabling them to better focus on their work responsibilities, while our 401(k) Plan provides a vehicle for tax-preferred retirement savings with additional compensation in the form of an employer match that adds to the overall desirability of our executive compensation package. For 2017, we provided an employer match under our 401(k) Plan equal to 100% of employee contributions up to 6% of eligible compensation, subject to the annual maximum contribution limit

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imposed by the Internal Revenue Service. None of our Named Executive Officers participated in any defined benefit pension plans or non-qualified deferred compensation plans.

Severance Agreements. We maintain severance and other compensatory agreements with our executive officers for a variety of reasons, including the fact that severance agreements can be an important recruiting tool in the market in which we compete for talent. Certain provisions in some of these agreements, such as confidentiality, non-solicitation and non-compete clauses, protect us and our unitholders after the termination of the employment relationship. We believe that it is appropriate to compensate former executives for these post-termination agreements, and that compensation helps to enhance the enforceability of these arrangements. Please see the section below entitled “Potential Payments Upon a Termination or Change in Control” for discussion regarding severance agreements with our Named Executive Officers.

Change in Control Agreements. In 2017, our General Partner entered into bonus agreements with Messrs. Williamson, Moxley and Allan. These bonus agreements provide that such Named Executive Officer will be eligible to receive a one-time lump sum cash payment in the event of a Change of Control (as such term is defined therein), so long as such Named Executive Officer remains employed by our General Partner through the date of the Change of Control. Please see the section below entitled “Potential Payments Upon a Termination or Change in Control” for discussion regarding change in control agreements with our Named Executive Officers.

Recoupment Policy. Equity awards granted under the LTIP are subject to recovery, including modification and forfeiture, for certain “Act[s] of Misconduct” as defined in the LTIP. We currently do not have a recovery policy applicable to annual cash bonuses, if any are awarded. The Compensation Committee will continue to evaluate the need to amend such a policy, in light of current legislative policies and economic and market conditions.

2017 Summary Compensation Table

The following table (the "Summary Compensation Table") sets forth certain information with respect to the compensation paid to our Named Executive Officers for the years ended December 31, 2016 and 2017:



Name and Principal Position	Year	Salary ($)	Bonus($)(1)	All other compensation ($)(2)	Total ($)
Bruce A. Williamson(3)	2017	1,000,000	—	16,827	1,016,827
Chairman, President and Chief Executive Officer	2016	—	—	190,000	190,000
John E. Bonn (4)	2017	65,236	300,000	2,051,282	2,416,518
Former President and Chief Executive Officer	2016	489,423	1,000,000	16,584	1,506,007
Joel D. Moxley	2017	397,000	457,750	16,884	871,634
Senior Vice President and Chief Commercial Officer	2016	394,231	794,000	16,584	1,204,815
Bret M. Allan	2017	330,000	377,500	16,884	724,384
Senior Vice President and Chief Financial Officer	2016	323,077	660,000	16,584	999,661

_______________________________________________________________________________

(1)

For 2017, includes a $297,750 bonus paid to Mr. Moxley and a $247,500 bonus paid to Mr. Allan. For 2017, includes $300,000 paid to Mr. Bonn which represents the portion of the 2016 Cash LTIP Award that would have been payable to Mr. Bonn on the next vesting date of April 1, 2017 but was paid as part of Mr. Bonn stepping down from our General Partner; $160,000 paid to Mr. Moxley representing a third of his 2016 Cash LTIP Award which vested on April 1, 2017; and $130,000 paid to Mr. Allan representing a third of his 2016 Cash LTIP Award which vested on April 1, 2017. For 2016, represents a $500,000 bonus paid to Mr. Bonn on each of April 22, 2016 and November 3, 2016; a $397,000 bonus paid to Mr. Moxley on each of April 22, 2016 and November 3, 2016; and a $330,000 bonus paid to Mr. Allan on each of April 22, 2016 and November 3, 2016.

(2)

For 2017, each of Messrs. Williamson, Moxley and Allan had a 401(k) match of $16,200 and Mr. Bonn had a 401(k) match of $2,905. For 2017, includes life insurance premiums for Mr. Williamson in the amount of $627, Mr. Bonn in the amount of $57, and Messrs. Moxley and Allan in the amount of $684 each. For 2017, Mr. Bonn had severance compensation in the total amount of $2,048,320. For 2016, each of Messrs. Bonn, Moxley and Allan had a 401(k) match of $15,900. For 2016, includes life insurance premiums for Messrs. Bonn, Moxley and Allan in the amount of $684 each. For 2016, represents board fees in the amount of $115,000 and a cash award in the amount of $75,000 to Mr. Williamson in his capacity as a director only.

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(3)	Mr. Williamson was elected to our General Partner on January 6, 2017 as Chairman, President and Chief Executive Officer. In 2016, Mr. Williamson served as a non-employee director of our General Partner. See our Current Report on Form 8-K filed with the SEC on January 9, 2017.


(4)	Mr. Bonn stepped down from our General Partner on January 6, 2017. See our Current report on Form 8-K, filed with the SEC on January 9, 2017.

A discussion of the material compensation information disclosed in the Summary Compensation Table is set forth in the "Compensation Components and Analysis" section above and following is a discussion of other material factors necessary to understanding the total compensation afforded to our Named Executive Officers:

Named Executive Officer LTIP Units. On March 10, 2015, the board of directors of our General Partner granted 66,353 phantom units to Mr. Bonn (14,537 of which vested on the first anniversary of the grant date and 51,816 of which were to vest in three cumulative annual installments on the anniversary of the grant date). On July 1, 2015, the board of directors of our General Partner granted 45,000 phantom units to Mr. Moxley (all of which vest in three cumulative annual installments on the anniversary of the grant date) and 36,000 phantom units to Mr. Allan (all of which vest in three cumulative annual installments on the anniversary of the grant date).

Except for the LTIP awards with one-year vesting as indicated above, the phantom units awarded to our Named Executive Officers vest in three cumulative annual installments, with one-third of the units vesting on each anniversary of the grant date, subject to continued employment through the applicable vesting date. Each phantom unit granted to our Named Executive Officers in 2015 was granted in tandem with corresponding distribution equivalent rights (which are discussed below). Generally, upon the grantee’s cessation of employment, all phantom units that have not vested will be forfeited. Phantom units will vest in full upon a cessation of service due to death or disability or upon a change in control.

Amended and Restated Long-Term Incentive Plan. Under the LTIP, certain officers (including our Named Executive Officers), employees and directors are eligible to receive awards with respect to our equity interests, thereby linking the recipients’ compensation directly to our performance. The description of the LTIP set forth below is a summary of the material features of the LTIP. This summary does not purport to be a complete description of all of the provisions of the LTIP.

On October 28, 2015, the board of directors of our General Partner unanimously approved the Amended and Restated 2012 Long-Term Incentive Plan (the “Amended LTIP”), which is substantially similar to our 2012 Long Term Incentive Plan (the “2012 LTIP”). Effective as of December 7, 2015, the unitholders holding a majority of the Partnership’s outstanding limited partnership units approved the Amended LTIP by written consent in lieu of a special meeting of unitholders. The Amended LTIP increased the number of Partnership common units that may be granted as awards from 1,750,000 to 6,250,000 (inclusive of the 1,750,000 common units authorized under our 2012 LTIP), with such amount subject to adjustment as provided for under the terms of the Amended LTIP if there is a change in the common units, such as a unit split or other reorganization. The Amended LTIP also extended the term of the LTIP to a period of 10 years following its adoption. The term LTIP, as used here, means the 2012 LTIP as amended by the Amended LTIP. The LTIP awards granted to the Named Executive Officers in 2015 were granted prior to the adoption of the Amended LTIP.

The LTIP provides for the grant, from time to time at the discretion of the board of directors of our General Partner or the Compensation Committee, of restricted units, phantom units, unit options, distribution equivalent rights and other unit-based awards. Pursuant to the LTIP and subject to further adjustment in the event of certain transactions or changes in capitalization, an aggregate 6,250,000 common units may be delivered pursuant to awards under the LTIP.

Units that are canceled or forfeited will be available for delivery pursuant to other awards. The LTIP is administered by the board of directors of our General Partner, although such administration function may be delegated to a committee (including the Compensation Committee) that may be appointed by the board of directors of our General Partner to administer the LTIP. The LTIP is designed to promote our interests, as well as the interests of our unitholders, by rewarding our directors, officers and employees for delivering desired performance results, as well as by strengthening our ability to attract, retain and motivate qualified individuals to serve as our directors, officers and employees.

Phantom Units. In 2016 and 2017, there were no units granted under the LTIP to our named executive officers. In 2015, the only grants under the LTIP were phantom units. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. The administrator of the LTIP may make grants of phantom units under the LTIP that contain such terms, consistent with the LTIP, as the administrator may determine are appropriate, including the period over which phantom units will vest. The administrator of the LTIP may, in its discretion,

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base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change in control (as defined in the LTIP) or as otherwise described in an award agreement.

The administrator of the LTIP, in its discretion, may also grant tandem distribution equivalent rights with respect to phantom units. Distribution equivalent rights are rights to receive an amount, in cash, units, restricted units and/or phantom units, equal in value to the distributions made on units during the period an award remains outstanding.

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

Amendment or Termination of LTIP. The administrator of the LTIP, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The LTIP will automatically terminate on the tenth anniversary of the date of the adoption of the Amended LTIP (as described above). The administrator of the LTIP also will have the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would impair materially the rights of the participant without the consent of the affected participant, and/or result in taxation to the participant under the Internal Revenue Code Section 409A.

In connection with the Merger, each award of phantom units of the Partnership granted under the LTIP that is outstanding as of immediately prior to the effective time of the Merger will be fully vested and settled in the form of Common Units of the Partnership, subject to applicable tax withholding, and will be converted into the right to receive 0.160 of a common unit representing limited partner interests in AMID at the effective time of the Merger.

2016 Cash-Based Long-Term Incentive Plan. On March 11, 2016, the board of directors of our General Partner approved the 2016 Cash-Based Long-Term Incentive Plan (the “2016 Cash LTIP”). The description of the 2016 Cash LTIP set forth below is a summary of the material features of the 2016 Cash LTIP. This summary does not purport to be a complete description of all of the provisions of the 2016 Cash LTIP.

The 2016 Cash LTIP provides for the grant, from time to time, of cash awards to certain of our employees. The 2016 Cash LTIP is administered by the board of directors of our General Partner, although such administration function may be delegated to a committee (including the Compensation Committee) comprised solely of two or more non-employee directors. The 2016 Cash LTIP is designed to promote our interests by strengthening our ability to retain and motivate employees.

Vesting Under 2016 Cash LTIP. Awards under the 2016 Cash LTIP (each, a “2016 Cash LTIP Award”) are determined by the Board or the Compensation Committee and are subject to the vesting of the cash award upon specified future dates. A third of each 2016 Cash LTIP Award granted to our Named Executive Officers vested on April 1, 2017 and a third of each 2016 Cash LTIP Award will vest on each of April 1, 2018, and April 1, 2019, subject to continued employment through the applicable vesting date. Generally, upon the grantee’s cessation of employment, any cash awarded pursuant to a 2016 Cash LTIP Award that has not vested will be forfeited. However, if the employee is terminated without cause (as defined in the Amended LTIP), then such employee is entitled to receive the portion of the 2016 Cash LTIP Award that would have been payable on the next vesting date, but shall forfeit any further unvested 2016 Cash LTIP Award. A 2016 Cash LTIP Award shall vest in full, subject to continued employment through the certain event, upon a termination due to death or disability (as defined in the Amended LTIP) or a change of control (as defined in the 2016 Cash LTIP).

Amendment or Termination of 2016 Cash LTIP. The Board or the Compensation Committee may amend or terminate any 2016 Cash LTIP Award or the 2016 Cash LTIP in its discretion provided that any amendment or termination adverse to any employee under the 2016 Cash LTIP requires the consent of such employee. The 2016 Cash LTIP shall terminate on the date that all awards are paid.

2016 Cash LTIP Awards. On April 12, 2016, the board of directors of our General Partner awarded our Named Executive Officers cash awards under the 2016 Cash LTIP. The portion of each 2016 Cash LTIP Award that vested in 2017 is reflected in the Summary Compensation Table.

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The 2016 Cash LTIP Awards are as follows:



Name	Award Value
John E. Bonn (1)	$	900,000
Joel D. Moxley (1)	$	480,000
Bret M. Allan (1)	$	390,000

(1)

For Messrs. Moxley and Allan, a third of each of their 2016 Cash LTIP Award vested on April 1, 2017 and a third of each of their 2016 Cash LTIP Award will vest on each of April 1, 2018 and April 1, 2019, subject to continued employment through the applicable vesting date. As noted herein, Mr. Bonn stepped down from our General Partner on January 6, 2017. Mr. Bonn received $300,000, which represents the portion of the 2016 Cash LTIP Award that would have been payable on the next vesting date of April 1, 2017.

Retention Agreements. On March 17, 2016, our General Partner entered into retention agreements (the “Retention Agreements”) with Messrs. Bonn, Moxley and Allan. The description of the Retention Agreements set forth below is a summary of the material features of the Retention Agreements. This summary does not purport to be a complete description of all of the provisions of the Retention Agreements.

Pursuant to the Retention Agreements, Messrs. Bonn, Moxley and Allan each received (i) a one-time special restructuring bonus in an amount equal to 100% of his then-current annual salary for remaining employed with our General Partner through the date that Holdings emerged from bankruptcy and (ii) a one-time special retention bonus in the amount equal to 100% of his then-current annual salary for remaining employed with our General Partner through November 1, 2016. For 2016, under the Retention Agreements, Mr. Bonn received a total payment of $1,000,000, Mr. Moxley received a total payment of $794,000, and Mr. Allan received a total payment of $660,000. Each of these retention amounts were paid by Holdings.

All Other Compensation. Please see the discussions above for a discussion of the base salaries, bonuses, long-term incentive compensation, benefits, perquisites and retirement arrangements paid or made available to our Named Executive Officers. Please also see the section below entitled “Outstanding Equity Awards at December 31, 2017” for a discussion of outstanding equity awards and the section below entitled “Potential Payments Upon a Termination or Change in Control” for a discussion of payments made upon termination of employment and certain change in control events.

Outstanding Equity Awards at December 31, 2017

Southcross Energy Partners, L.P. Equity Awards. The following table provides information regarding LTIP units held by our Named Executive Officers as of December 31, 2017:



	Southcross Energy Partners, L.P. - LTIP Units
Name	Number of time-vesting units that have not vested		Fair value of time-vesting units that have not vested(1)
Bruce A. Williamson	—	(2)	$	—
John E. Bonn	—	(3)	$	—
Joel D. Moxley	15,000	(4)	$	25,350
Bret M. Allan	12,000	(5)	$	20,280

^{__________________________________________________________________________________________}


(1)	Amounts were calculated based on the closing price per common unit on December 29, 2017 of $1.69.


(2)	As noted herein, Mr. Williamson was appointed Chairman, President and Chief Executive Officer of our General Partner on January 6, 2017.


(3)	As noted herein, Mr. Bonn stepped down from our General Partner and forfeited his unvested LTIP awards on January 6, 2017.

(4)

Represents the remaining number of unvested time-vesting LTIP units awarded to Mr. Moxley on July 1, 2015, subject to his continued employment through the applicable vesting date. The units vest (on a one for one basis) in three cumulative annual installments on the anniversary of the grant date. 15,000 phantom units of the 45,000 phantom units awarded to Mr. Moxley vested on each of July 1, 2016 and July 1, 2017.

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(5)

Represents the remaining number of unvested time-vesting LTIP units awarded to Mr. Allan on July 1, 2015, subject to his continued employment through the applicable vesting date. The units vest (on a one for one basis) in three cumulative annual installments on the anniversary of the grant date. 12,000 phantom units of the 36,000 phantom units awarded to Mr. Allan vested on each of July 1, 2016 and July 1, 2017.

Potential Payments Upon a Termination or Change in Control

Severance and Change in Control Benefits. Our Named Executive Officers are entitled to severance payments and benefits upon certain terminations of employment and, in certain cases, upon a change in control.

Messrs. Moxley and Allan entered into severance agreements with our General Partner that provide for severance benefits upon certain terminations of employment. Mr. Bonn had an employment agreement with our General Partner that provided for severance benefits upon certain terminations of his employment. Mr. Bonn stepped down on January 6, 2017. Bruce Williamson entered into an employment agreement with our General Partner on January 6, 2017.

Mr. Williamson's Severance and Change in Control Benefits. On January 6, 2017, our General Partner entered into an employment agreement with Mr. Williamson, the Chairman, President and Chief Executive of our General Partner (the “Williamson Employment Agreement”), which provides for an initial one year term, unless earlier terminated, that automatically extends for one year periods unless notice is given otherwise prior to the expiration of the then-current term. Mr. Williamson will receive an annualized base salary of $1,000,000 and will not be eligible for any annual incentive bonus. Mr. Williamson is entitled to receive certain benefits and reimbursement of certain expenses.

Under the Williamson Employment Agreement, upon a termination of Mr. Williamson’s employment by us for any reason, Mr. Williamson is entitled to receive (i) any portion of his Annual Base Salary through the date of termination not theretofore paid, (ii) any expenses owed and (iii) any accrued and unused PTO owed. Upon termination of Mr. Williamson’s employment by us without cause or by Mr. Williamson for good reason, then Mr. Williamson will also receive the remainder of his Annual Base Salary for the then current term, in addition to other payments and benefits described in the Williamson Employment Agreement. If the termination by us without cause or by Mr. Williamson for good reason occurs following a change in control (as defined in the Williamson Employment Agreement), the severance payment will be the annual base salary through the first anniversary of the date of termination. Additionally, the severance payment is conditioned upon the execution of a general release of claims and continued compliance with certain non-competition and non-solicitation restrictions for twelve months following termination and certain confidentiality provisions.

A for “cause” termination would occur under the Williamson Employment Agreement if Mr. Williamson (i) willfully fails to perform satisfactorily his lawful material duties or to devote his full time and effort to his position, (ii) actually violates any material company policy that remains un-remedied after reasonable notice to cure the violation, (iii) fails to follow lawful and reasonable directives from the board of directors of our General Partner, (iv) commits gross negligence or material misconduct, (v) commits any intentional act of fraud, embezzlement, misappropriation, material misconduct, conversion of assets or breach of fiduciary duty or (vi) any felony conviction.

A “good reason” termination would be permitted under the Williamson Employment Agreement within 90 days after the following occurs (without Mr. Williamson’s written consent): (i) Mr. Williamson is removed as Chief Executive Officer or as a member of the Board, (ii) a material diminution of his base salary or (iii) a change in the location of Mr. Williamson’s employment to a location more than 50 miles from Dallas or Houston, Texas.

During his employment and for one year following his termination, Mr. Williamson is subject to certain non-competition and non-solicitation provisions set forth in the Williamson Employment Agreement. Mr. Williamson is also subject to certain confidentiality provisions during and after his employment.

On March 27, 2017, Mr. Williamson entered into a Bonus Agreement with our General Partner which provides that Mr. Williamson will be eligible to receive a one-time lump sum cash payment in the event of a Change of Control (as such term is defined therein), so long as Mr. Williamson remains employed by our General Partner as of the Change of Control. If prior to such Change of Control, Mr. Williamson’s employment terminates for any reason, the bonus is forfeited. In connection with the execution of the Merger Agreement, the board of our General Partner determined that Mr. Williamson will be entitled to receive $1,500,000 upon a Change of Control (which will occur upon consummation of the Contribution). The cash bonus payment will be paid by Holdings.

Mr. Bonn's Severance and Change in Control Benefits. On March 5, 2015, our General Partner entered into an employment agreement with John E. Bonn, who served as President and Chief Executive Officer of our General Partner (the “Bonn Employment Agreement”). The Bonn Employment Agreement provided for an initial three-year term, unless earlier terminated. The Bonn Employment Agreement automatically extended for one year periods unless notice was given otherwise prior to the expiration of the then-current term. Mr. Bonn was entitled to receive an annual base salary of $450,000 for the first

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year, $500,000 for the second year and not less than $500,000 for each year thereafter, as determined by the board of directors of our General Partner. Mr. Bonn was eligible to receive an annual cash bonus based on annual performance targets in an amount determined by the board of directors of our General Partner in its discretion with a target annual bonus equal to Mr. Bonn’s salary for such year. Mr. Bonn was also eligible to receive LTIP awards as determined by the board of directors of our General Partner. Mr. Bonn was also entitled to receive certain benefits and reimbursement of certain expenses, including relocation expenses.

By virtue of the Bonn Employment Agreement, upon his termination without “cause” on January 6, 2017, Mr. Bonn was entitled to receive (i) a payment consisting of (a) any portion of Mr. Bonn’s Annual Base Salary through the date of termination that was unpaid, (b) any expenses owed to Mr. Bonn, (c) any accrued and unused paid time off owed to Mr. Bonn, (d) any amount arising under any employee benefit plans, and (e) payment of an Annual Bonus earned in 2016, but unpaid; and (ii) a Severance Payment of (a) two times his then-current annual base salary, (b) two times his target annual bonus for 2017, (c) an amount equal to the cost of COBRA coverage for 18 months after termination and (d) $100,000 since Mr. Bonn was terminated during the second year of the Bonn Employment Agreement, subject to Mr. Bonn complying with certain restrictions in a severance agreement and the terms of other ancillary agreements to which Mr. Bonn is a party. On February 21, 2017, Mr. Bonn executed a Severance Agreement and General Release and received severance payments over the next ten months in 2017 pursuant to the Bonn Employment Agreement.

With regard to Mr. Bonn’s 2016 Cash LTIP Award, since Mr. Bonn was terminated without cause (as defined in the LTIP), Mr. Bonn was entitled to receive the portion of the 2016 Cash LTIP Award that would have been payable on the next vesting date, but forfeited any further unvested 2016 Cash LTIP Award. A 2016 Cash LTIP Award would have vested in full, subject to continued employment through the certain event, upon a termination due to death or disability (as defined in the LTIP) or a change of control (as defined in the 2016 Cash LTIP). For additional information regarding the vesting of Mr. Bonn’s 2016 Cash LTIP Award, see the discussion under the Summary Compensation Table above.

For one year following his termination, Mr. Bonn is subject to certain non-competition and non-solicitation provisions set forth in the Bonn Employment Agreement. Mr. Bonn is also subject to certain confidentiality provisions after his employment.

Mr. Moxley's Severance and Change in Control Benefits. Under Mr. Moxley's severance agreement, dated as of June 15, 2015, as amended by that certain Amendment No. 1 to Severance Agreement dated August 1, 2016 (as amended, the "Moxley Severance Agreement"), upon termination of Mr. Moxley’s employment by us within 12 months following a sale event (as defined in the Moxley Severance Agreement), termination without “cause” or by Mr. Moxley for “good reason,” Mr. Moxley is entitled to receive (i) base salary through the date of termination, (ii) an amount equal to two times his target annual bonus, (iii) an amount equal to two times his then-current annual base salary and (iv) an amount equal to the cost of COBRA coverage for 18 months after termination. Additionally, severance payments are conditioned upon the execution of a general release of claims and continued compliance with certain non-solicitation restrictions for twelve months following termination and certain confidentiality provisions.

A for “cause” termination would occur under Mr. Moxley’s severance agreement if Mr. Moxley (i) fails to satisfactorily perform his material duties or to devote his full time and effort to his position, (ii) violates any material company policy that remains un-remedied after reasonable notice to cure the violation, (iii) fails to follow lawful directives from the Chairman, President and Chief Executive Officer, the board of directors of our General Partner or Mr. Moxley’s direct supervisor, (iv) his negligence or material misconduct, (v) his dishonesty or fraud or (vi) any felony conviction.

A “good reason” termination would be permitted under Mr. Moxley’s severance agreement if: (i) there is material change in Mr. Moxley’s job duties and responsibilities, (ii) a material diminution of his base salary unless the reduction applies to all employees of the General Partner employed at similar levels or (iii) a change in the location that Mr. Moxley regularly works of more than 25 miles.

With regard to Mr. Moxley’s LTIP phantom unit awards, upon certain transactions generally resulting in a change in control of our General Partner or the Partnership or cessation of his services due to death or disability, any unvested phantom units will vest in full. For additional information regarding the vesting of the phantom units, see the discussion under the Summary Compensation Table above.

With regard to Mr. Moxley’s 2016 Cash LTIP Award, if Mr. Moxley is terminated without cause (as defined in the LTIP), then Mr. Moxley is entitled to receive the portion of the 2016 Cash LTIP Award that would have been payable on the next vesting date, but shall forfeit any further unvested 2016 Cash LTIP Award. A 2016 Cash LTIP Award shall vest in full, subject to continued employment through the certain event, upon a termination due to death or disability (as defined in the LTIP) or a change of control (as defined in the 2016 Cash LTIP). For additional information regarding the vesting of Mr. Moxley’s 2016 Cash LTIP Award, see the discussion under the Summary Compensation Table above.

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On March 27, 2017, Mr. Moxley entered into a Bonus Agreement with our General Partner which provides that Mr. Moxley will be eligible to receive a one-time lump sum cash payment in the event of a Change of Control (as such term is defined therein), so long as Mr. Moxley remains employed by our General Partner as of the Change of Control. If prior to such Change of Control, Mr. Moxley’s employment terminates for any reason, the bonus is forfeited. In connection with the execution of the Merger Agreement, the board of our General Partner determined that Mr. Moxley will be entitled to receive $600,000 upon a Change of Control (which will occur upon consummation of the Contribution). The cash bonus payment will be allocated equally between the Partnership and Holdings.

Mr. Allan's Severance and Change in Control Benefits. Mr. Allan's Severance Agreement, dated as of June 8, 2015, as amended by that certain Amendment No. 1 to Severance Agreement dated August 1, 2016, has the same terms as Mr. Moxley's Severance Agreement, described above.

Mr. Allan also has the same vesting as Mr. Moxley and Mr. Bonn with respect to his LTIP phantom unit awards and 2016 Cash LTIP Awards.

On March 27, 2017, Mr. Allan entered into a Bonus Agreement with our General Partner which provides that Mr. Allan will be eligible to receive a one-time lump sum cash payment in the event of a Change of Control (as such term is defined therein), so long as Mr. Allan remains employed by our General Partner as of the Change of Control. If prior to such Change of Control, Mr. Allan employment terminates for any reason, the bonus is forfeited. In connection with the execution of the Merger Agreement, the board of our General Partner determined that Mr. Allan will be entitled to receive $600,000 upon a Change of Control (which will occur upon consummation of the Contribution). The cash bonus payment will be allocated equally between the Partnership and Holdings.

Director Compensation

Officers, employees or paid consultants of our General Partner who also serve as directors do not receive additional compensation for their service as directors. As of January 6, 2017, Mr. Biegler is no longer an employee and received compensation as a non-employee director in 2017. As of January 6, 2017, Mr. Williamson became an officer of our General Partner and did not receive compensation as a director in 2017.

On December 15, 2016, the board of directors of our General Partner and the Compensation Committee revised our Southcross Energy Partners GP, LLC Non-Employee Director Compensation Arrangement. In 2017, our directors who are not officers, employees or paid consultants of our General Partner only received cash compensation. For 2017, our General Partner awarded $75,000 in cash to the directors who are not officers, employees or paid consultants of our General Partner. Such directors were not awarded an equity grant.

Specifically, directors were also eligible for the following in 2017:


i.	An annual retainer of $65,000, to be paid quarterly in February, April, July and October;


ii.	An annual retainer of $15,000 for the Chairperson of the Audit Committee, to be paid quarterly in February, April, July and October;


iii.	An annual retainer of $5,000 for the Chairperson of the Compensation Committee, to be paid quarterly in February, April, July and October;


iv.	An annual retainer of $7,500 for the Chairperson of the Conflicts Committee, to be paid quarterly in February, April, July and October;


v.	An annual retainer of $5,000 for each Independent Director for each committee in which they are a member (in addition to any fees they receive as a Chairperson), to be paid quarterly in February, April, July and October; and


vi.	A per diem amount for assistance with special projects, in an amount commensurate with the amount payable for attendance at Board or Committee meetings.

Pursuant to the Non-Employee Director Compensation Arrangement, compensation for directors who serve for only a portion of a year is pro-rated for time served. Our non-employee directors are reimbursed for certain expenses incurred for their services to us.

We previously adopted the Southcross Energy Partners, L.P. Non-Employee Director Deferred Compensation Plan, pursuant to which non-employee directors of our general partner could elect on an annual basis to defer all earned cash and/or equity compensation until the director is no longer a director of our general partner. All amounts deferred were converted into phantom units from us, which are entitled to receive quarterly distributions from us (to the extent declared). These quarterly distributions were also be converted to phantom units. At the conclusion of the deferral period, the accrued phantom units will

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be paid to the director in the form of (i) cash for deferrals of cash compensation equal to the fair market value as of such date and (ii) common units for deferrals of equity compensation. For the calendar year 2016, Mr. Williamson elected to defer his non-employee director compensation. For the calendar year 2017, the Board authorized and approved the cessation of future deferral elections starting with the fees payable in 2017. On October 31, 2017, in connection with the Merger Agreement, the Non-Employee Director Deferred Compensation Plan was amended such that the plan will be terminated effective as of one business day prior to the Closing (as defined in the Merger Agreement) (the “Deferred Compensation Termination Effective Date”). All of Mr. Williamson’s accrued phantom units from service in 2013 through 2016 will be liquidated and paid to Mr. Williamson in a lump sum cash payment (without any equity compensation), as soon as practicable following the Deferred Compensation Termination Effective Date but no later than the Closing Date (as defined in the Merger Agreement).

Mr. Downie informed us that in accordance with the internal policies of Tailwater and the terms of the limited partnership agreements for the Tailwater funds, all cash compensation otherwise payable to Mr. Downie as a result of being a director of our General Partner should be paid directly to Tailwater.

Mr. Henderson also informed us that in accordance with the internal policies of EIG and the terms of the limited partnership agreements for the EIG funds, all cash compensation otherwise payable to Mr. Henderson as a result of being a director of our General Partner should be paid directly to EIG. As of December 1, 2017, Mr. Henderson resigned as a director and Mr. Randall Wade was elected as a director as EIG’s representative. Mr. Wade did not receive compensation as a director in 2017.

Director Compensation for 2017

The following table presents the cash compensation earned, paid or awarded to each of our non-employee directors during the year ended December 31, 2017:



Name	Fees earned or paid in cash (1)		Cash awards		All other Compensation (2)		Total
David W. Biegler (3)	$	65,000	$	75,000	$	21,538	$	161,538
Jason H. Downie (4)	$	70,000	$	75,000	$	—	$	145,000
Wallace C. Henderson (5)	$	65,000	$	75,000	$	—	$	140,000
Jerry W. Pinkerton	$	117,500	$	75,000	$	—	$	192,500
Nicholas J. Caruso	$	100,000	$	75,000	$	—	$	175,000
Andrew A. Cameron (6)	$	100,000	$	75,000	$	—	$	175,000
Randall S. Wade (7)	$	—	$	—	$	—	$	—


(1)	For Messrs. Pinkerton, Caruso and Cameron, fees also include a $20,000 one-time fee for additional responsibilities and duties as a member of the Conflicts Committee in 2017


(2)	For Mr. Biegler, includes a $10,000 fee paid as a consultant to the Conflicts Committee in 2017 and $11,538 paid as an employee in 2017.


(3)	As of January 6, 2017, Mr. Biegler is no longer an employee and received compensation as a non-employee director in 2017.


(4)	Director associated with Tailwater. Cash compensation was paid to Tailwater.


(5)	Director associated with EIG. Cash compensation was paid to EIG. As of December 1, 2017, Mr. Henderson resigned as a director.


(6)	Mr. Cameron was elected to the board of our General Partner on January 1, 2017.


(7)	Director associated with EIG. As of December 1, 2017, Mr. Wade was elected as a director and did not receive any cash compensation in 2017.

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

The following table sets forth certain information regarding the beneficial ownership of our units as of February 23, 2018 by:


•	each person known to us to own beneficially 5% or more of any class of our outstanding units (including any "group" as that term is used in Section 13(d)(3) of the Exchange Act);


•	each of the directors and named executive officers of our General Partner; and


•	all of the directors and executive officers of our General Partner as a group.

All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders, as the case may be, or based on a review of the copies of reports furnished to us.

Our General Partner is indirectly owned 100% by Holdings. EIG and Tailwater each indirectly own approximately one-third of Holdings, and a group of consolidated lenders under Holdings' revolving credit facility and term loan own the remaining one-third of Holdings. The general partner of Holdings is Southcross Holdings GP LLC ("Holdings GP"), of which EIG and Tailwater each indirectly own approximately one-third, and a group of consolidated lenders under Holdings' revolving credit facility and term loan own the remaining one-third of Holdings GP. Our General Partner owns all of the general partner interests in us.

The amounts and percentage of units beneficially owned are reported on the basis of SEC regulations governing the determination of beneficial ownership of securities. Under the SEC regulations, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote, or to direct the voting, of such security, and/or “investment power,” which includes the power to dispose, or to direct the disposition of, such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, a right to acquire beneficial ownership of a security within 60 days of February 23, 2018 by a person, if any, are deemed to be outstanding for computing the percentage of outstanding securities of the class by such person, but are not deemed to be outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting power and sole investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

The percentages of units beneficially owned are based on a total of 48,623,615 common units, 12,213,713 subordinated units and 18,656,071 Class B Convertible Units outstanding as of February 23, 2018.

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Name and address of beneficial owner(1)	Common units beneficially owned	Percentage of common units beneficially owned		Subordinated units beneficially owned(1)	Percentage of subordinated units beneficially owned		Class B Convertible Units beneficially owned(1)	Percentage of Class B Convertible Units beneficially owned		Percentage of total common, subordinated and Class B Convertible Units beneficially owned
Our Holding Company:
Southcross Holdings LP(2)(3)(4)	26,492,074	54.5	%	12,213,713	100.0	%	18,656,071	100	%	72.2	%
5% Owners Not Listed Above or Below:
EIG BBTS Holdings, LLC(5)	26,492,074	54.5	%	12,213,713	100.0	%	18,656,071	100	%	72.2	%
TW Southcross Aggregator LP(6)	26,492,074	54.5	%	12,213,713	100.0	%	18,656,071	100	%	72.2	%
Directors and Named Executive Officers of Our General Partner:
Bret M. Allan (2)	17,436	*		—	—		—	—		*
David W. Biegler(2)	128,472	*		—	—		—	—		*
John E. Bonn(2)	71,679	*		—	—		—	—		*
Andrew A. Cameron(2)	—	—		—	—		—	—		—
Nicholas J. Caruso, Jr.(2)	6,454	*		—	—		—	—		*
Jason H. Downie(6)(7)	26,492,074	54.5	%	12,213,713	100.0	%	18,656,071	100	%	72.2	%
Wallace C. Henderson(8)	—	—		—	—		—	—		—
Joel D. Moxley(2)	20,294	*		—	—		—	—		*
Jerry W. Pinkerton(2)	14,739	*		—	—		—	—		*
Bruce A. Williamson(2)(9)	12,739	*		—	—		—	—		*
Randall Wade(5)(10)	26,492,074	54.5	%	12,213,713	100.0	%	18,656,071	100	%	72.2	%
All current directors and executive officers of our General Partner as a group (consisting of 10 persons)(6)(8)(9)(10)	26,707,948	54.9	%	12,213,713	100.0	%	18,656,071	100	%	72.4	%


*	An asterisk indicates that the person or entity owns less than one percent.

(1)

This beneficial ownership table was prepared as of February 23, 2018. The subordinated units convert into common units on a one-for-one basis on the expiration of the Subordination Period (as defined in the Partnership Agreement). The Class B Convertible Units convert into common units at the Class B Conversion Rate (as defined in our Partnership Agreement) on the Class B Conversion Date (as defined in the Partnership Agreement). Because such subordinated units and Class B Convertible Units were acquired in connection with transactions having the purpose or effect of changing or influencing the control of us, such subordinated units and Class B Convertible Units are considered converted for purposes of the calculations of the amounts noted under Rule 13d-3(d)(1)(i) of the Exchange Act. Pursuant to Rule 13d-3(d)(1)(i), the subordinated units and Class B Convertible Units are deemed outstanding for computing the percentage of the class owned by such beneficial owner, but not deemed to be outstanding for the purpose of computing the percentage of the class for any other person. The beneficial ownership reported for the Class B Convertible Units includes additional Class B Convertible Units issued in kind as distributions.


(2)	The address for this person or entity is 1717 Main Street, Suite 5200, Dallas, Texas 75201.


(3)	Holdings, through its wholly-owned subsidiaries, owns 100% of our General Partner, 26,492,074 of our common units, 12,213,713 of our subordinated units and 18,656,071 of our Class B Convertible Units.

(4)

Based on a Schedule 13D/A filed with the SEC on November 14, 2017 and a Form 4 filed with the SEC on February 9, 2018. Each filing was made jointly by Southcross Holdings LP, Southcross Holdings GP LLC, Southcross Holdings Intermediary LLC, Southcross Holdings Guarantor GP LLC, Southcross Holdings Guarantor LP, Southcross Holdings Borrower GP LLC and Southcross Holdings Borrower LP. Each party to the Schedule 13D, as amended, shares voting and dispositive power. The address for each party to the Schedule 13D, as amended, is 1717 Main Street, Suite 5200, Dallas, Texas 75201.

(5)

Based on a Schedule 13D/A filed with the SEC on November 14, 2017 and a Form 4 filed with the SEC on February 9, 2018. Each filing was made jointly by EIG BBTS Holdings, LLC, EIG Management Company, LLC, EIG Asset Management, LLC, EIG Global Energy Partners, LLC, The R. Blair Thomas 2010 Irrevocable Trust, R. Blair Thomas, The Randall Wade 2010 Irrevocable Trust, The Kristina Wade 2010 Irrevocable Trust and Randall S. Wade. Each party to the Schedule 13D, as amended, shares voting and dispositive power. Based on the relationship of Randall S. Wade to Southcross Holdings Borrower LP, Mr. Wade, a director of our General Partner, may be deemed to indirectly beneficially own the common units, subordinated units and the Class B Convertible Units held by Southcross Holdings Borrower LP. The address for each party to the Schedule 13D, as amended, is 1700 Pennsylvania Ave. NW, Suite 800, Washington, D.C. 20006.

(6)

Based on a Schedule 13D/A filed with the SEC on November 14, 2017 and a Form 4 filed with the SEC on February 9, 2018. Each filing was made jointly by TW Southcross Aggregator LP, TW/LM GP Sub, LLC, Tailwater Energy Fund I LP, TW GP EF-I, LP, TW GP EF-I GP, LLC, TW GP Holdings, LLC, Tailwater Holdings, LP, Tailwater Capital LLC, Jason H. Downie and Edward Herring. Each party to the Schedule 13D, as amended, shares voting and dispositive power. Based on the relationship of Jason H. Downie to Southcross Holdings Borrower LP, Mr. Downie, a director of our General Partner, may be deemed to indirectly beneficially own the common units, subordinated units and Class B Convertible Units held by Southcross Holdings Borrower LP. The address for each party to the Schedule 13D, as amended, is 2021 McKinney Avenue, Suite 1250, Dallas, Texas 75201.

(7)

Mr. Downie owns no units directly. Includes 26,492,074 common units, 12,213,713 subordinated units and 18,656,071 Class B Convertible Units indirectly owned by Holdings. Based on the relationship of Mr. Downie to Southcross Holdings Borrower LP, Mr. Downie may be deemed to indirectly beneficially own the common units, subordinated units and Class B Convertible Units held by Southcross Holdings Borrower LP. Mr. Downie disclaims beneficial ownership of the securities reported, except to the extent of Mr. Downie’s indirect pecuniary interest.


(8)	As of December 1, 2017, Mr. Henderson resigned as director. The address for Mr. Henderson is 1700 Pennsylvania Ave. NW, Suite 800, Washington, D.C. 20006.

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(9)

Represents phantom units issued under the Non-Employee Director Deferred Compensation Plan whereby Mr. Williamson has the right to acquire common units within 30 days of termination of his services. Mr. Williamson has elected to defer all earned compensation under the Non-Employee Director Deferred Compensation Plan until he is no longer a director of our General Partner. In accordance with the Non-Employee Director Deferred Compensation Plan, Mr. Williamson has a total of 157,978 phantom units, 145,239 of which will be settled in cash equal to the fair market value of our common units on the date of termination of Mr. Williamson’s services (and which are not included in the table). In connection with that certain Agreement and Plan of Merger, dated as of October 31, 2017, by and among Southcross Energy Partners GP, LLC, the Issuer, American Midstream Partners, LP, a Delaware limited partnership ("AMID"), American Midstream GP, LLC, a Delaware limited liability company, and Cherokee Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of AMID ("Merger Sub") (the “Merger Agreement”) pursuant to which AMID will acquire control over the Issuer through the merger of the Issuer with and into Merger Sub, the Plan was amended and will be terminated effective as of one (1) business day prior to the Closing (as defined in the Merger Agreement) (the “Termination Effective Date”). Mr. Williamson's account in the Plan shall be liquidated and paid to him in the form of a lump sum cash payment as soon as practicable following the Termination Effective Date, but no later than the Closing Date (as defined in the Merger Agreement). For the purpose of avoiding ambiguity, any portion of Mr. Williamson's account attributable to equity compensation shall be paid in the form of cash regardless that it would otherwise be paid in the form of units under the Plan.

(10)

As of December 1, 2017, Mr. Wade was elected as a director. Mr. Wade owns no units directly. Includes 26,492,074 common units, 12,213,713 subordinated units and 18,656,071 Class B Convertible Units indirectly owned by Holdings. Based on the relationship of Mr. Wade to Southcross Holdings Borrower LP, Mr. Wade may be deemed to indirectly beneficially own the common units, subordinated units and Class B Convertible Units held by Southcross Holdings Borrower LP. Mr. Wade disclaims beneficial ownership of the securities reported, except to the extent of Mr. Wade’s indirect pecuniary interest.


(11)	Does not include any unvested phantom units granted to such directors and executive officers under the LTIP.

Holdings has pledged the common units, subordinated units, and Class B Convertible Units that it owns as security under Holding’s credit facilities. These credit facilities include customary provisions regarding potential events of default. Therefore, if an event of default occurred under Holding’s credit facilities, a change in ownership of the units owned by Holdings could occur. See Part I, Item 1 under "Recent Developments" for a description of the transactions with AMID which may result in a change of control for us.

Securities Authorized for Issuance Under Equity Compensation Plan(1)

We have one compensation plan under which our common units are authorized for issuance, the LTIP. This equity compensation plan was approved by our unitholders. The following table sets forth certain information relating to the LTIP as of December 31, 2017:



	(a)	(b)		(c)
Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column(a))
Equity compensation plans approved by securities holders	98,096	—		5,330,004
Equity compensation plans not approved by security holders	—	—		—
Total	98,096	$	—	5,330,004


(1)	See Note 10 to our consolidated financial statements for more information. No value is shown in column (b) of the table because the phantom units do not have an exercise price.


Item 13.	Certain Relationships and Related Transactions, and Director Independence

As of February 23, 2018, Holdings owns 26,492,074 common units, 12,213,713 subordinated units and 18,656,071 Class B Convertible Units, representing a combined 72.2% limited partner interest in us. In addition, Holdings owns and controls our General Partner, which owns a 2.0% General Partner interest in us and all of our incentive distribution rights. Our General Partner owns all of the general partner interests in us. EIG and Tailwater each indirectly own approximately one-third of Holdings, and a group of consolidated lenders under Holdings' revolving credit facility and term loan (the "Lenders") own the remaining one-third of Holdings. The general partner of Holdings is Southcross Holdings GP LLC ("Holdings GP"), of which EIG and Tailwater each indirectly own approximately one-third, and the Lenders own the remaining one-third of Holdings GP.

Our common units represent limited partner interests in us. The holders of our common units are entitled to participate in our distributions (to the extent distributions are declared) and are entitled to exercise the rights and privileges available to limited partners under our Partnership Agreement. In accordance with the requirements of the Equity Cure Agreement, Holdings was issued 8,029,729 common units on May 2, 2016 and 359,459 common units on May 13, 2016.

The following table summarizes the distributions and payments owed by us to our General Partner and its affiliates in connection with our ongoing operations and liquidation. Certain of these distributions and payments were determined among affiliated entities and, consequently, are not the result of arm's-length negotiations.



Operational Stage
Distributions to our General Partner and its affiliates	Previously, we generally made cash distributions (except with respect to our Class B Convertible Units, which are paid in Class B PIK Units) of 98.0% to our unitholders pro rata (including to Holdings, as the holder of a 61.5% limited partnership interest in us) and 2.0% to our General Partner, assuming our General Partner makes any capital contributions necessary to maintain its 2.0% general partner interest in us. In addition, if distributions exceed the minimum quarterly distribution and target distribution levels, our General Partner is entitled to increasing percentages of the distributions, up to 48.0% of the distributions above the highest target distribution level in connection with its incentive distribution rights. The board of directors of our General Partner suspended paying a quarterly distribution with respect to the fourth quarter of 2015 and every quarter of 2016 to reserve any excess cash for the operation of our business. The board of directors of our General Partner and our management believe this suspension to be in the best interest of our unitholders and will continue to evaluate our ability to reinstate the distribution in future periods. More importantly, we are restricted under the Fifth Amendment on paying a distribution until our Consolidated Total Leverage Ratio is below 5.0. See Notes 2 and 3 to our consolidated financial statements.
Payments to our General Partner and its affiliates	Our General Partner does not receive a management fee or other compensation for its management of us. However, our General Partner and its affiliates are entitled to reimbursement for all expenses incurred on our behalf, including, among other items, compensation expense for all employees required to manage and operate our business. Our Partnership Agreement provides that our General Partner will determine the amount of these reimbursed expenses. In addition, as described below, these employees provide services to affiliated entities, including Holdings, and the expenses for these services are allocated by the board of directors of our General Partner.
Withdrawal or removal of our General Partner	If our General Partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case, for an amount equal to the fair market value of those interests.
Liquidation Stage
Liquidation	Upon our liquidation, our partners, including our General Partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Southcross Energy Partners GP, LLC (our General Partner)

Our General Partner does not receive a management fee or other compensation for its management of us. However, our General Partner and its affiliates are entitled to reimbursements for all expenses incurred on our behalf, including, among other items, compensation expense for all employees required to manage and operate our business. During the year ended December 31, 2016, we incurred expenses related to these reimbursements, which are reflected in operating expenses in our consolidated statements of operations.

Holdings Chapter 11 Reorganization

On March 28, 2016, Holdings and certain of its subsidiaries (excluding 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 bankruptcy with its Lenders being issued 33.34% of the limited partner interests in Holdings in exchange for the elimination of certain funded debt obligations. EIG and Tailwater each contributed $85 million in cash (or $170 million in the aggregate) in exchange for each Sponsor receiving 33.33% of the limited partner interests in Holdings. In addition, Holdings committed to provide us $50 million (as part of the Equity Cure Agreement defined below), out of the $170 million in new equity contributed to Holdings from the Sponsors, to provide us with liquidity to comply with the applicable financial covenants set forth in our credit agreement at the time.

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Holdings Equity Cure Contribution Agreement, Investment Agreement, Backstop Agreement, and Equity Cure Contribution Amendment

In accordance with the requirements of the Equity Cure Agreement, Holdings was issued 8,029,729 common units on May 2, 2016 and 359,459 common units on May 13, 2016. See Notes 2 and 6 to the consolidated financial statements for additional details.

In connection with the execution of the Fifth Amendment, on December 29, 2016, the Partnership entered into (i) the Investment Agreement with Holdings and Wells Fargo Bank, N.A., (ii) the Backstop Agreement with Holdings, Wells Fargo Bank, N.A. and the Sponsors and (iii) the Equity Cure Contribution Amendment with Holdings.

On January 2, 2018, we notified Holdings that a Full Investment Trigger (as defined in the Investment Agreement) occurred on December 31, 2017. Pursuant to the Backstop Agreement, on January 2, 2018, Holdings delivered a Backstop Demand (as defined in the Investment Agreement) for each Sponsor to fund their respective pro rata portions of the Sponsor Shortfall Amount (as defined in the Investment Agreement) of $15.0 million in accordance with the Backstop Agreement. As consideration for the amount provided directly to us by the Sponsors pursuant to the Backstop Agreement, we issued to the Sponsors senior unsecured notes of the Partnership in an aggregate principal amount of $15.0 million (each, an "Investment Note" and collectively, the “Investment Notes”). The Investment Notes mature on November 5, 2019 and bear interest at a rate of 12.5% per annum. Interest on the Investment Notes shall be paid in kind (other than with respect to interest payable (i) on or after the maturity date, (ii) in connection with prepayment, or (iii) upon acceleration of the Investment Note, which shall be payable in cash); provided that all interest shall be payable in cash on or after December 31, 2018. The Investment Notes are the unsecured obligation of the Partnership subordinate in right of payment to any of our secured obligations under the Third A&R Revolving Credit Agreement.

Recent Lack of Quarterly Distributions

Board of Directors

The board of directors of our General Partner is comprised of seven directors. Pursuant to the organizational documents of the general partner of Holdings, two directors (one of whom must be independent) on our board of directors will be appointed by each of EIG, Tailwater and the group of lenders who received membership interest in Holdings in connection with Holdings’ Chapter 11 reorganization. Bruce Williamson serves as chairman of the board as of January 6, 2017. David W. Biegler remains as one of the directors of our General Partner.

All of our non-employee directors are compensated equally for similar responsibilities and reimbursed for expenses incurred for their services to us. For the years ended December 31, 2017 and 2016, we paid EIG and Tailwater $0.3 million and $0.2 million, respectively, for director fees and related expenses. These expenses are reflected in general and administrative expenses in our consolidated statements of operations.

Shared Services with Southcross Holdings LP and Other Affiliates

Certain of the employees of our General Partner perform management, administrative, operational and workforce related services to affiliated entities, including Holdings, which owns 100% of our General Partner, and an affiliate that is partially owned by EIG and Tailwater, two of our Sponsors. The expenses associated with these services, which are shared with these entities, are recorded in general and administrative expense in our statement of operations and are allocated in a manner approved by the board of directors and Conflicts Committee. For the years ended December 31, 2017 and 2016, we allocated $1.6 million and $1.4 million, respectively, to Holdings.

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The Conflicts Committee of the board of directors of our General Partner has reviewed the cost allocation methodology applicable to these services and, based on representations from management, determined that the fees charged were fair.

Other Transactions with Affiliates

We had accounts receivable due from affiliates of $33.2 million and $8.0 million as of December 31, 2017 and 2016, respectively, and accounts payable due to affiliates of $0.4 million and $50.6 million as of December 31, 2017 and 2016, respectively. The affiliate receivable and payable balances are related primarily to transactions associated with Holdings, noted above, and our joint venture investments. See Note 12 to our consolidated financial statements. The receivable balance due from Holdings is current as of December 31, 2017.

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

We have a Code of Business Conduct and Ethics that requires the board of directors of our General Partner or its Conflicts Committee to review periodically all related-person transactions that are required to be disclosed under SEC rules and, when appropriate, to authorize or ratify all such transactions. If the board of directors of our General Partner or its Conflicts Committee considers ratification of a related-person transaction and determines not to so ratify, the Code of Business Conduct and Ethics provides that our management will make all reasonable efforts to cancel or annul the transaction.

Our Code of Business Conduct and Ethics provides that, in determining whether to recommend the initial approval or ratification of a related-person transaction, the board of directors of our General Partner or its Conflicts Committee should consider all of the relevant facts and circumstances available, including (if applicable), but not limited to: (i) whether there is an appropriate business justification for the transaction, (ii) the benefits that accrue to us as a result of the transaction, (iii) the terms available to unrelated third parties entering into similar transactions, (iv) the impact of the transaction on director independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediately family member of a director is a partner, shareholder, member or executive officer), (v) the availability of other sources for comparable products or services, (vi) whether it is a single transaction or a series of ongoing, related transactions, and (vii) whether entering into the transaction would be consistent with our Code of Business Conduct and Ethics.

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See Part II, Item 10 of this report for a discussion regarding director independence.


Item 14.	Principal Accountant Fees and Services

We have engaged Deloitte & Touche LLP as our independent registered public accounting firm. The following table summarizes fees we have paid Deloitte & Touche LLP for the audit of our annual financial statements and other services rendered for the years ended December 31, 2017 and 2016:



	Year ended December 31,
	2017		2016
Audit fees⁽¹⁾	$	1,470,500	$	1,453,000
Audit-related fees⁽²⁾	75,000		110,500
Tax fees⁽³⁾	50,000		30,003
	$	1,595,500	$	1,593,503


(1)	The Audit fees are fees billed for professional services for the audit and quarterly reviews of the Partnership’s consolidated financial statements, review of other SEC filings, including anticipated registration statements, and issuance of comfort letters and consents.


(2)	Audit-related fees are fees billed for assurance and related services related to implementation of Section 404 of the Sarbanes-Oxley Act.


(3)	Tax fees are billed for sales tax planning and advisory services.

Audit Committee Approval of Audit and Non-Audit Services

The Audit Committee of the board of directors of our General Partner has adopted a policy with respect to services which may be performed by Deloitte & Touche LLP. This policy lists specific audit-related and tax services as well as any other services that Deloitte & Touche LLP is authorized to perform and sets out specific dollar limits for each specific service, which may not be exceeded without additional Audit Committee authorization. The Audit Committee receives quarterly reports on the status of expenditures pursuant to that policy. The Audit Committee reviews the policy at least annually in order to approve services and limits for the current year. Any service that is not clearly enumerated in the policy must receive specific pre-approval by the Audit Committee or by its chairman, to whom such authority has been conditionally delegated, prior to engagement.

The Audit Committee has approved the appointment of Deloitte & Touche LLP as independent registered public accounting firm to conduct the audit of our financial statements for the year ended December 31, 2017.

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Item 15.	Exhibits and Financial Schedules

(a) Financial Statements

(1) Included in Part II, Item 8 of this report.




Report of Independent Registered Public Accounting Firm	69
Consolidated Balance Sheets as of December 31, 2017 and 2016	70
Consolidated Statements of Operations for the Years Ended December 31, 2017 and 2016	71
Consolidated Statements of Cash Flows for the Years Ended December 31, 2017 and 2016	72
Consolidated Statements of Changes in Partners' Capital for the Years Ended December 31, 2017 and 2016	73
Notes to Consolidated Financial Statements	74

(2) All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.

(3) Exhibit Index.

An "Exhibit Index" has been filed as part of this report beginning in sub-item (b) below of this item and is incorporated herein by reference.

Schedules other than those listed above are omitted because they are not required, not material, not applicable or the required information is shown in the financial statements or notes thereto.

Agreements attached or incorporated herein as exhibits to this report are included to provide investors with information regarding the terms and conditions of such agreements and are not intended to provide any other factual or disclosure information about the Partnership or the other parties to the agreements.

Such agreements may contain representations and warranties by the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and (i) should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate, (ii) have been qualified by disclosures that were made to the other party or parties in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement, (iii) may apply standards of materiality in a way that is different from what may be viewed as material to you or other investors and (iv) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments. Accordingly, the representations and warranties in such agreements may not describe the actual state of affairs as of the date they were made or at any other time.

(b) Exhibits and Exhibit Index



Exhibit Number		Description
2.1		Agreement and Plan of Merger, dated October 31, 2017 by and among American Midstream Partners, L.P., American Midstream GP, LLC, Southcross Energy Partners, L.P. and Southcross Energy Partners GP, LLC (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K dated November 2, 2017).
2.2		Contribution Agreement, dated October 31, 2017 by and among American Midstream Partners, L.P., American Midstream GP, LLC and Southcross Holdings LP (incorporated by reference to Exhibit 2.2 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2017).
3.1		Certificate of Limited Partnership of Southcross Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).
3.2		Third Amended and Restated Agreement of Limited Partnership of Southcross Energy Partners, L.P., dated as of August 4, 2014 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K dated August 4, 2014).
3.3		Certificate of Formation of Southcross Energy Partners GP, LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).

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Exhibit Number		Description
3.4		Second Amended and Restated Limited Liability Company Agreement of Southcross Energy Partners GP, LLC, dated as of August 4, 2014 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K dated August 4, 2014).
10.1#		Form of Bonus Agreement by and between Southcross Energy Partners GP, LLC, and certain key employees (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated March 27, 2017).
10.2		Letter Agreement, dated October 31, 2017 by and among Southcross Holdings LP and Southcross Energy Partners, L.P. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated November 2, 2017).
10.3#		Amendment to the Southcross Energy Partners, L.P. Non-Employee Director Deferred Compensation Plan, dated October 31, 2017 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K dated November 2, 2017).
10.4		Form of Qualifying Note (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated January 22, 2018).
10.5		Third Amended and Restated Revolving Credit Agreement, dated as of August 4, 2014, by and among Southcross Energy Partners, L.P., Wells Fargo Bank, N.A., as Administrative Agent, UBS Securities LLC and Barclays Bank PLC, as Co-Syndication Agents, JPMorgan Chase Bank, N.A., as Documentation Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated August 4, 2014).
10.6		First Amendment to Third Amended and Restated Revolving Credit Agreement, by and among the Partnership, as borrower, Wells Fargo Bank, N.A., as Administrative Agent, and the lenders and other parties thereto, dated as of May 7, 2015 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K dated May 7, 2015).
10.7		Limited Waiver and Second Amendment to Third Amended and Restated Revolving Credit Agreement, by and among the Partnership, as borrower, Wells Fargo Bank, N.A., as Administrative Agent, and the lenders and other parties thereto, dated as of August 4, 2016 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2016).
10.8		Waiver and Third Amendment to Third Amended and Restated Revolving Credit Agreement, by and among the Partnership, as borrower, Wells Fargo Bank, N.A., as Administrative Agent, and the lenders and other parties thereto, dated as of November 8, 2016 (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2016).
10.9		Waiver and Fourth Amendment to Third Amended and Restated Revolving Credit Agreement, by and among the Partnership, as borrower, Wells Fargo Bank, N.A., as Administrative Agent, and the lenders and other parties thereto, dated as of December 9, 2016 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated December 12, 2016).
10.10		Waiver and Fifth Amendment to Third Amended and Restated Revolving Credit Agreement, by and among the Partnership, as borrower, Wells Fargo Bank, N.A., as Administrative Agent, and the lenders and other parties thereto, dated as of December 29, 2016 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated January 3, 2017).
10.11		Term Loan Credit Agreement, dated as of August 4, 2014, by and among Southcross Energy Partners, L.P., Wilmington Trust, National Association (successor to Wells Fargo Bank, N.A.), as Administrative Agent, UBS Securities LLC and Barclays Bank PLC, as Co-Syndication Agents, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K dated August 4, 2014).
10.12#		Southcross Energy Partners, L.P. Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated December 8, 2015).
10.13#		Form of Phantom Unit Award Agreement (incorporated by reference to Exhibit 10.5 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).
10.14#		Southcross Energy Partners GP, LLC and Southcross GP Management Holdings, LLC 2014 Equity Incentive Plan and Form of Unit Award Agreement (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K dated August 4, 2014).
10.15#		Southcross Energy Partners GP, LLC Non-Employee Director Compensation Arrangement (incorporated by reference to Exhibit 10.12 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2012).
10.16#		Southcross Energy Partners, L.P. Non-Employee Director Deferred Compensation Plan (incorporated by reference to Exhibit 10.13 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2012).
10.17		Contribution Agreement, dated as of June 11, 2014, by and among Southcross TS Midstream Services, LP, Southcross Energy Partners, L.P. and Southcross Energy GP LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated June 11, 2014).

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Exhibit Number		Description
10.18#		Employment Agreement, dated as of March 5, 2015, by and between Southcross Energy Partners GP, LLC and John E. Bonn (incorporated by reference to Exhibit 10.10 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2015).
10.19		Purchase, Sale and Contribution Agreement, by and among Southcross Energy Partners, L.P., Southcross CCNG Gathering Ltd., Southcross NGL Pipeline Ltd., FL Rich Gas Services, LP, Southcross Midstream Utility, LP, Frio LaSalle Pipeline, LP and Southcross Holdings LP, dated as of May 7, 2015 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated May 7, 2015).
10.20#		Severance Agreement, dated as of June 8, 2015, by and between Southcross Energy Partners GP, LLC and Bret M. Allan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated June 8, 2015).
10.21#		Amendment No. 1 to Severance Agreement, dated August 1, 2016, by and between Southcross Energy Partners GP, LLC and Bret M. Allan (incorporated by reference to Exhibit 10.17 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2016).
10.22#		Severance Agreement, dated as of June 15, 2015, by and between Southcross Energy Partners GP, LLC and Joel D. Moxley (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated June 15, 2015).
10.23#		Amendment No. 1 to Severance Agreement, dated August 1, 2016, by and between Southcross Energy Partners GP, LLC and Joel D. Moxley (incorporated by reference to Exhibit 10.19 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2016).
10.24		Equity Cure Contribution Agreement, dated March 17, 2016, by and between Southcross Energy Partners, L.P. and Southcross Holdings LP (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated March 22, 2016).
10.25		First Amendment to Equity Cure Contribution Agreement, dated December 29, 2016, by and between Southcross Energy Partners, L.P. and Southcross Holdings LP (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K dated December 29, 2016).
10.26		Investment Agreement, dated December 29, 2016, by and among Southcross Energy Partners, L.P., Southcross Holdings LP and Wells Fargo Bank, N.A. (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K dated December 29, 2016).
10.27		Backstop Investment Commitment Letter, dated December 29, 2016, by and among Southcross Energy Partners, L.P., Southcross Holdings LP, Wells Fargo Bank, N.A. and the Sponsors party thereto (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K dated December 29, 2016).
10.28#		Southcross Energy Partners, L.P. 2016 Cash-Based Long-Term Incentive Plan dated March 11, 2016 and Form of Award Agreement (incorporated by reference to Exhibit 10.18 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2015).
10.29#		Retention Agreement, dated March 17, 2016, by and between Southcross Energy Partners GP, LLC and Mr. John E. Bonn (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K dated March 17, 2016).
10.30#		Retention Agreement, dated March 17, 2016, by and between Southcross Energy Partners GP, LLC and Mr. Bret M. Allan (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K dated March 17, 2016).
10.31#		Retention Agreement, dated March 17, 2016, by and between Southcross Energy Partners GP, LLC and Mr. Joel D. Moxley (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K dated March 17, 2016).
10.32		Form of Senior Unsecured PIK Note, dated as of January 7, 2016, by and between Southcross Energy Partners, L.P. and the Lender party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated January 7, 2016).
10.33#		Employment Agreement, dated January 6, 2017, by and between Bruce A. Williamson and Southcross Energy Partners GP, LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated January 6, 2017).
10.34#		Severance Agreement and General Release, dated February 21, 2017, by and between Southcross Energy Partners GP, LLC and John E. Bonn (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated February 21, 2017).
10.35#		Southcross Energy Partners GP, LLC Non-Employee Director Compensation Arrangement, beginning January 1, 2017 (incorporated by reference to Exhibit 10.31 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2016).
21.1*		List of Subsidiaries of Southcross Energy Partners, L.P.
23.1*		Consent of Deloitte & Touche LLP.

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Exhibit Number		Description
31.1*		Certification of Chief Executive Officer required by Rule 13a-14(a)/15d-14(a).
31.2*		Certification of Chief Financial Officer required by Rule 13a-14(a)/15d-14(a).
32.1*		Certifications of Chief Executive Officer and Chief Financial Officer required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
101.INS*†		XBRL Instance Document
101.SCH*†		XBRL Taxonomy Extension Schema
101.CAL*†		XBRL Taxonomy Extension Calculation Linkbase
101.DEF*†		XBRL Taxonomy Extension Definition Linkbase
101.LAB*†		XBRL Taxonomy Extension Label Linkbase
101.PRE*†		XBRL Extension Presentation Linkbase


#	Management contracts or compensatory plans or arrangement.


*	Filed or furnished herewith.


†	The financial information contained in the XBRL (eXtensible Business Reporting Language)-related documents is unaudited.

Not applicable.


Item 16.	Form 10-K Summary

Not applicable.

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SIGNATURES

Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



		Southcross Energy Partners, L.P.
		By: Southcross Energy Partners GP, LLC, its General Partner
Date:	March 1, 2018	By:	/s/ BRUCE A. WILLIAMSON
			Bruce A. Williamson President, Chief Executive Officer and Chairman of the Board

Pursuant to the requirements of the Securities Exchange Act of 1934, the following persons on behalf of the registrant and in the capacities and on the dates indicated have signed this report below.



SIGNATURE	TITLE	DATE

/s/ BRUCE A. WILLIAMSON	President, Chief Executive Officer and Chairman of the Board	March 1, 2018
Bruce A. Williamson	(Principal Executive Officer)

/s/ BRET M. ALLAN	Senior Vice President and Chief Financial Officer	March 1, 2018
Bret M. Allan	(Principal Financial Officer and Principal Accounting Officer)

/s/ DAVID W. BIEGLER	Director	March 1, 2018
David W. Biegler	Director

/s/ ANDREW A. CAMERON	Director	March 1, 2018
Andrew A. Cameron	Director

/s/ NICHOLAS J. CARUSO	Director	March 1, 2018
Nicholas J. Caruso	Director

/s/ JASON DOWNIE	Director	March 1, 2018
Jason Downie	Director

/s/ RANDALL S. WADE	Director	March 1, 2018
Randall S. Wade	Director

/s/ JERRY W. PINKERTON	Director	March 1, 2018
Jerry W. Pinkerton	Director

124

Year Ended December 31,

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