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, 2018

OR

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

For the transition period from                                to                               

Commission file number: 001-35719

Southcross Energy Partners, L.P.

(Exact name of registrant as specified in its charter)

DELAWARE (State or other jurisdiction of incorporation or organization)	45-5045230 (I.R.S. Employer Identification No.)
1717 Main Street, Suite 5200 Dallas, TX (Address of principal executive offices)	75201 (Zip Code)

(214) 979-3700

www.southcrossenergy.com

(Registrant's telephone number, including area code)

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

Title of each class	Name of each exchange on which registered
None	None

Securities registered pursuant to Section 12(g) of the Act: Common units representing limited partner interests

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 every Interactive Data File required to be submitted 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 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, a smaller reporting company, or an emerging growth 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.

Large accelerated filer o Accelerated filer o Non-accelerated filer x 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 ¨   No x

The aggregate market value of common units held by non-affiliates of the registrant on June 30, 2018 was approximately $34,323,887 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 March 20, 2019, the registrant has 48,694,891 common units, 12,213,713 subordinated units and 19,996,781 Class B Convertible Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

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

/d: Per day

/gal: Per gallon

Bbls: Barrels

Condensate: Hydrocarbons that are produced from natural gas reservoirs but remain liquid at normal temperature and pressure

Lean gas: Natural gas that is low in NGL content

MMBtu: One million British thermal units

Mcf: One thousand cubic feet

MMcf: One million cubic feet

NGLs: Natural gas liquids, which consist primarily of ethane, propane, isobutane, normal butane, natural gasoline and stabilized condensate

Residue gas: The pipeline quality natural gas remaining after natural gas is processed and NGLs and other matters are removed

Rich gas: Natural gas that is high in NGL content

Throughput: The volume of natural gas or NGLs transported or passing through a pipeline, plant, terminal or other facility

Y-grade: Commingled mix of NGL components extracted via natural gas processing normally consisting of ethane, propane, isobutane, butane and natural gasoline

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INDEX TO ANNUAL REPORT ON FORM 10-K

For the Year Ended December 31, 2018

PART I
Item 1.	Business	6
Item 1A.	Risk Factors	23
Item 1B.	Unresolved Staff Comments	53
Item 2.	Properties	53
Item 3.	Legal Proceedings	54
Item 4.	Mine Safety Disclosures	54
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities	55
Item 6.	Selected Financial Data	56
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	56
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	73
Item 8.	Financial Statements and Supplementary Data	74
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	110
Item 9A.	Controls and Procedures	110
Item 9B.	Other Information	110
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	110
Item 11.	Executive Compensation	118
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	124
Item 13.	Certain Relationships and Related Transactions, and Director Independence	128
Item 14.	Principal Accountant Fees and Services	131
PART IV
Item 15.	Exhibits and Financial Statement Schedules	132
Item 16.	Form 10-K Summary	135
	Signatures	136

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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") 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 reflect management's 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:

• our bankruptcy proceedings and the effect of those proceedings on our ongoing and future operations;

• the outcome of potential strategic alternatives to maximize the benefit of our stakeholders as part of the Chapter 11 process, which may include a sale of certain or substantially all of our assets under Section 363 of the Bankruptcy Code or a plan of reorganization to equitize certain indebtedness as an alternative to the sale process;

• our ability to negotiate a plan of reorganization in connection with the Chapter 11 process, including the restructuring of our indebtedness;

• our future cash flows and the adequacy to fund our ongoing operations and the significant costs associated with the bankruptcy process, including our ability to limit these costs by obtaining confirmation of a successful plan of reorganization in a timely manner;

• our ability to maintain compliance with debt covenants and meet debt service obligations associated with DIP Financing (as defined herein);

• future capital requirements and availability of financing during and post-emergence from bankruptcy, including limitations on our ability to incur certain types of indebtedness under our debt agreements and to refinance or replace existing debt obligations;

• our business strategies, including our business strategies post-emergence from bankruptcy;

• our ability to maintain relationships with suppliers, customers, employees and other third parties as a result of our Chapter 11 filings;

• our ability to attract and retain key personnel;

• the volatility of prices for natural gas, crude oil and NGLs (and demand for the products derived from these commodities) has the potential to affect the amount of the exploration, development and production of natural gas in the area of our assets;

• 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;

• our dependence upon EPIC Midstream Holdings, LP and EPIC Y-Grade Holdings, LP for a significant portion of our revenues as a result of the sale by Southcross Holdings LP of its Robstown fractionation facility;

• actions taken or inactions or nonperformance by third parties, including suppliers, contractors, operators, processors, transporters and customers;

• the impacts on our common units as a result of the delisting from the New York Stock Exchange, including the negative impact on our common unit price, volatility and liquidity associated with trading on over-the-counter markets and the number of investors willing to hold or acquire our common units;

• 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 and spread risk;

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• the effectiveness of our hedging activities or our decisions not to undertake hedging activities;

• our ability to generate sufficient operating cash flow;

• the effects of downtime associated with our assets or the assets of third parties interconnected with our systems;

• operating hazards, fires, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

• the failure of our processing, fractionation and treating plants to perform as expected, including outages for unscheduled maintenance or repair;

• the effects of laws and governmental regulations and policies;

• the effects of existing and future litigation;

• the effects of the termination of the Merger Agreement (as defined below);

• 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;

• our ability to continue as a going concern; and

• other financial, operational and legal risks and uncertainties detailed from time to time in our filings with the SEC.

Developments in any of these areas could cause actual results to differ materially from those anticipated or projected, affect our ability to 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 update publicly 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. 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, one treating 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 (the "Class B Convertible Units") and currently owns 54.4% of our common units. Our General Partner owns an approximate 2.0% interest in us and all of our incentive distribution rights. 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 Holdings' former term loan lenders own the remaining one-third of Holdings.

Bankruptcy proceeding under Chapter 11

On April 1, 2019 (the "Petition Date"), the Partnership and certain of the Partnership's subsidiaries, including Southcross Energy Partners, L.P., our General Partner, Southcross Energy Finance Corp., Southcross Energy Operating, LLC, Southcross Energy GP LLC, Southcross Energy LP LLC, Southcross Gathering Ltd., Southcross CCNG Gathering Ltd., Southcross CCNG Transmission Ltd., Southcross Marketing Company Ltd., Southcross NGL Pipeline Ltd., Southcross Midstream Services, L.P., Southcross Mississippi Industrial Gas Sales, L.P., Southcross Mississippi Pipeline, L.P., Southcross Gulf Coast Transmission Ltd., Southcross Mississippi Gathering, L.P., Southcross Delta Pipeline LLC, Southcross Alabama Pipeline LLC, Southcross Nueces Pipelines LLC, Southcross Processing LLC, FL Rich Gas Services GP, LLC, FL Rich Gas Services, LP, FL Rich Gas Utility GP, LLC, FL Rich Gas Utility, LP, Southcross Transmission, LP, T2 EF Cogeneration Holdings, LLC, and T2 EF Cogeneration LLC (collectively the “Filing Subsidiaries” and, together with the Partnership and General Partner, the “Debtors”) filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). The Debtors’ have proposed to jointly administer their Chapter 11 cases under the caption In re Southcross Energy Partners, L.P., Case No. 19-10702 (the “Chapter 11 Cases”). We will continue to operate our businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The Debtors have filed with the Bankruptcy Court motions seeking a variety of first-day relief, which are designed primarily to minimize the impact of the Chapter 11 proceedings on our operations, customers and employees and includes a motion to obtain post-petition financing. We expect to continue our operations without interruption during the pendency of the Chapter 11 proceedings.

For the duration of the of the Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to significant risks and uncertainties associated with Chapter 11 proceedings. As a result of these significant risks and uncertainties, our assets, liabilities, unitholders’ equity (deficit), officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in these financial statements may not accurately reflect our operations, properties and capital plans following the Chapter 11 proceedings. See further discussion of the Chapter 11 proceedings in Note 14 to our consolidated financial statements.

Recent Developments

Delisting of Common Units from NYSE

On February 27, 2019, the New York Stock Exchange (“NYSE”) notified the Partnership that the staff of NYSE Regulation, Inc. (the “NYSE Regulation”) had determined to commence proceedings to delist our common units. The NYSE Regulation reached its decision to delist our common units pursuant to Rule 802.01C of the NYSE’s Listed Company Manual, as the Partnership’s unit price had fallen below the NYSE’s continued listing standard with average closing price of less than

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$1.00 over a consecutive 30 trading-day period and failed to cure this non-compliance within the required timeframe. The NYSE also suspended trading after the market close on the NYSE on February 27, 2019.

Effective February 28, 2019, our common units commenced trading on the OTCQX Marketplace under the ticker symbol "SXEE". On March 20, 2019, the NYSE filed with the SEC a notification of removal from listing and registration on Form 25 to delist our common units and terminate the registration of our common units under Section 12(b) of the Securities Exchange Act of 1934. The delisting became effective on April 1, 2019.

Holdings' Sale of Robstown Facility

On October 4, 2018, EPIC Midstream Holdings, LP (“EPIC”) and EPIC Y-Grade Holdings, LP, a subsidiary of EPIC ("EPIC Y-Grade"), entered into a definitive equity purchase agreement (the "Robstown Purchase Agreement") with Holdings and Holdings Borrower to acquire Holdings' Robstown fractionation facility ("Robstown") and related pipelines that enables Robstown to receive natural gas liquids from various supply sources and several short pipelines that allow the delivery of fractionated products to Corpus Christi-area markets. Under the terms of the agreement, EPIC assumed all of the NGL purchase and sale agreements associated with Robstown, including certain natural gas liquids sales and transportation agreements with the Partnership. The sale was completed in November 2018.

Management Changes

Effective September 17, 2018, the board of directors of our General Partner (the "Partnership GP Board") elected James W. Swent III as the Chairman, President and Chief Executive Officer of our General Partner. Mr. Swent succeeded David W. Biegler, who stepped down as Chairman, President and Chief Executive Officer of the General Partner after serving as the acting Chairman, President and Chief Executive Officer of our General Partner when Bruce A. Williamson, stepped down from those positions for personal reasons in August 2018. Mr. Biegler continues to serve as a director on the Partnership GP Board.

Effective January 4, 2019, Michael B. Howe joined our General Partner as Senior Vice President and Chief Financial Officer. Mr. Howe succeeded Bret M. Allan, the former Senior Vice President and Chief Financial Officer of our General Partner who resigned from all positions with our General Partner effective January 4, 2019.

Effective February 1, 2019, the Partnership GP Board elected William C. Boyer as our General Partner’s Senior Vice President and Chief Operating Officer.

Distribution Suspension

The Partnership GP Board suspended paying a quarterly distribution with respect to the fourth quarter of 2015 and every quarter of 2016, 2017 and 2018 to conserve any excess cash for the operation of our business and due to restrictions imposed by our debt instruments. See Notes 2 and 3 to our consolidated financial statements.

Ownership Structure

The following table depicts our ownership structure as of December 31, 2018:

Description	Percentage ownership
Ownership by non-affiliates:
Public common units	27.0	%
Southcross Holdings LP's ownership:
Common units	32.2	%
Subordinated units	14.9	%
Class B Convertible Units	23.9	%
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.

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Our liquidity and ability to maintain compliance with debt covenants have been negatively impacted by our level of indebtedness. Despite our significant efforts to improve our financial condition, we have continued to face increasing liquidity concerns.

During 2017 and 2018, we focused on restructuring our balance sheet to improve our liquidity and financial condition.

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, (i) the total aggregate commitments under the Third A&R Revolving Credit Agreement were reduced from $200 million to $115 million and the sublimit for letters of credit was also reduced from $75 million to $50 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 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 were required to maintain minimum levels of Consolidated EBITDA (as defined in the Fifth Amendment) on a quarterly basis and were 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 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 and Term Loan 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”).

On July 29, 2018, we terminated the Agreement and Plan of Merger, dated October 31, 2017, by and among us, our General Partner, American Midstream Partners, LP, a Delaware limited partnership (“AMID”), American Midstream GP, LLC, a Delaware limited liability company and the general partner of AMID (“AMID GP”), and Cherokee Merger Sub LLC, a Delaware limited liability company and wholly owned subsidiary of AMID (“Merger Sub”) as amended by that certain Amendment No. 1 to Merger Agreement, dated as of June 1, 2018, by and among us, our General Partner, AMID, AMID GP and Merger Sub (as amended, the “Merger Agreement”), since the transactions contemplated by the Merger Agreement was not completed on or prior to June 15, 2018. As previously disclosed, under the Merger Agreement, we were to merge with and into Merger Sub, with the Partnership surviving the merger as a wholly owned subsidiary of AMID.

On August 10, 2018, we entered into the sixth amendment (the “Sixth Amendment”) to the Third A&R Revolving Credit Agreement which, among other things, reduced the Consolidated Interest Coverage Ratio from 1.50 to 1.00 to 1.25 to 1.00 for the period ending on June 30, 2018. See Note 6 to our consolidated financial statements.

During management's ongoing assessment of the Partnership's financial forecast, the board of directors of Southcross Holdings GP, LLC (the “Holdings GP Board”) and the board of directors of our General Partner (the “Partnership GP Board”), together with our management, determined that in the then current corporate capital structure and absent continued access to equity cures from our Sponsors or a significant equity infusion from a third party, or absent additional amendments to its Third A&R Revolving Credit Agreement (which matures on August 4, 2019) or waivers of the March 31, 2019 requirement to comply with the Consolidated Total Leverage Ratio and minimum Adjusted EBITDA (both as defined in the Fifth Amendment) and Consolidated Interest Coverage Ratio (as defined in the Sixth Amendment), the Partnership was not expected to be able to comply with such financial covenants, which would have triggered an event of default under the Senior Credit Facilities. As a

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result of the Partnership’s expected inability to comply with its financial covenants within the twelve months from the issuance of this Annual Form 10-K, together with the maturity date of the Third A&R Revolving Credit Agreement being in less than twelve months, management determined that there are conditions and events that raise substantial doubt about the Partnership’s ability to continue as a going concern.

In March 2019, in light of (a) the August 4, 2019 maturity of the Third A&R Revolving Credit Agreement, (b) the impending non-compliance with our Consolidated Total Leverage Ratio, minimum Adjusted EBITDA and Consolidated Senior Secured Leverage Ratio (each as defined in the Fifth Amendment - see Note 2 and 6 to our consolidated financial statements) at March 31, 2019 that would result in an event of default under the Senior Credit Facilities, (c) our non-compliance with our minimum Adjusted EBITDA and Consolidated Interest Coverage Ratio as of December 31, 2018 (see Note 6 to our consolidated financial statements); and (d) the inclusion of a going concern uncertainty explanatory paragraph in the audit opinion on our consolidated financial statements, which constitutes an event of default under the Senior Credit Facilities, we elected not to make the approximately $7.4 million interest payment on our Term Loan that was due on March 29, 2019. While we have been in discussions with our creditors, those discussions did not produce an agreement that would enable us to address effectively, in a holistic manner, the impending issues adversely impacting our business, including (i) impending maturity of the Third A&R Revolving Credit Agreement, (ii) current and potential near-term breaches of certain financial covenants, and (iii) certain other potential defaults under our Senior Credit Facilities.

Despite our efforts to improve our financial condition, we continued to face increasing liquidity concerns. As of March 20, 2019, our liquidity was $2.1 million. On April 1, 2019, the Partnership and the Filing Subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. We were not able to reach an agreement with our creditors for a plan of reorganization prior to the Petition Date. Therefore, the outcome of our Chapter 11 process is subject to a high degree of uncertainty and is dependent upon factors outside of our control, including actions of the Court and our creditors.

On April 1, 2019, we filed a motion seeking entry of an order authorizing the Debtors to enter into the Debtor-in-Possession financing (“DIP Financing”) to, among other things, provide additional liquidity to fund our operations during the Chapter 11 process.

Pursuant to a Commitment Letter dated as of March 31, 2019 and Form Credit Agreement attached thereto (the “DIP Credit Agreement” and, the facility thereunder, the “DIP Facility”), to be entered into by Southcross, as borrower, its direct and indirect Debtor subsidiaries, as guarantors (the “Guarantors” and, together with Southcross, the “Loan Parties”), certain of our creditors under the Senior Credit Facilities, as lenders (the “DIP Lenders”) and letter of credit issuers (the “DIP L/C Issuers”), and Wilmington Trust, National Association, as administrative agent (the “DIP Agent”), the DIP Lenders have agreed to provide to the Loan Parties the DIP Financing in an aggregate principal amount of $255 million, consisting of (i) a senior secured priming superpriority term loan in the aggregate principal amount of $72.5 million (the “DIP New Money Loan”), (ii) a senior secured priming superpriority term loan in the aggregate principal amount of $55 million (the “DIP LC Loan” and, together with the DIP New Money Loans, the “DIP Term Loans”) to cash collateralize a letter of credit sub-facility for the issuance of letters of credit by certain issuing banks that will be party to the DIP Credit Agreement (the “DIP L/C Facility”), and (iii) a senior secured priming superpriority term loan in the aggregate principal amount of $127.5 million, which will be subject and subordinate to the DIP New Money Facility and the DIP L/C Facility, to refinance dollar-for-dollar term loans outstanding under the Term Loan Agreement owed to the DIP Lenders (the “DIP Roll-Up Loan” and, together with the DIP Term Loans, the “DIP Loans”). The DIP Loans are subject to approval by the Bankruptcy Court. The proceeds of the DIP Loans will be used for purposes permitted by the Bankruptcy Court and the DIP Credit Agreement, including (i) working capital and other general corporate purposes of the Loan Parties, including the refinancing of certain term loans and letters of credit, (ii) to pay transaction costs, professional fees, and other obligations and expenses incurred in connection with the DIP Facilities, the Chapter 11 Cases, and the transactions contemplated thereunder, and (iii) to make adequate protection payments to Southcross’s creditors under the Senior Credit Facilities to the extent set forth in any order entered by the Bankruptcy Court.

The DIP Facilities will mature on the earliest of (i) the date that is six months after the Petition Date (subject to one three month extension with the consent of the DIP Lenders constituting the required lenders under the DIP Facility), (ii) the effective date of a Chapter 11 plan, (iii) the date on which all or substantially all of the assets of the Loan Parties are sold in a sale under a Chapter 11 plan or pursuant to Section 363 of the Bankruptcy Code, and (iv) the date the DIP Facilities are accelerated following an event of default thereunder.  Subject to certain exceptions, the DIP Facility will be secured by a senior perfected security interest in substantially all of the assets of the Loan Parties, including the collateral securing the Senior Credit Facilities and any other previously unencumbered assets.

We continue to engage in discussions with our creditors regarding the terms of a financial restructuring plan. In conjunction with the Chapter 11 process, we will explore potential strategic alternatives to maximize value for the benefit of our stakeholders, which may include a sale of certain or substantially all of our assets under Section 363 of the Bankruptcy Code or a plan of reorganization to equitize certain indebtedness as an alternative to the sale process.

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Competitive Strengths

We believe that the following are our 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. We also believe that the 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 sustainability 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.

• 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. Many of our field operating managers and supervisors have long-standing experience operating our assets.

• 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 54.4% 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 and financial expertise 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.

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The following tables provide information regarding our assets as of and for the year ended December 31, 2018:

	As of December 31, 2018	Year Ended December 31, 2018
Gathering systems and intrastate pipelines	Miles	Average throughput volumes of natural gas (MMcf/d)
South Texas	2,019	442
Mississippi/Alabama	1,072	166
Total	3,091	608

	As of December 31, 2018	Year Ended December 31, 2018
Processing plants	Approximate design of gas processing capacity (MMcf/d)	Average volume of processed gas (MMcf/d)
Woodsboro	200	140
Lone Star	300	103
Total	500	243

	As of December 31, 2018	Year Ended December 31, 2018
Fractionation plants	Approximate design of fractionation capacity (Bbls/d)	Average volume of NGLs sold from output (Bbls/d)
Bonnie View (1)	22,500	—
Total	22,500	—

	As of December 31, 2018
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 was being sold to Holdings in accordance with our affiliate Y-grade sales agreement and was being fractionated at Robstown. However, during the fourth quarter of 2018, Holdings completed the sale of Robstown to EPIC. Under the terms of the Robstown Purchase Agreement, EPIC assumed all of the NGL purchase and sale agreements associated with Robstown, including those with the Partnership through December 31, 2019, as described above. As a result of the Robstown sale, Bonnie View will continue to serve as a backup option for EPIC to the extent Robstown is unable to fractionate our Y-grade product. In addition, EPIC has the option to request the Partnership to restart Bonnie View for the benefit of EPIC through December 31, 2019. At this time, we have no plans to restart Bonnie View and we will continue to operate the facility as a truck unloading facility and pipeline Y-grade receipt point.

We own equity interests in two joint ventures in South Texas with a subsidiary of Targa Resources Corp. ("Targa") as our joint venture partner. These two joint ventures, T2 Eagle Ford Gathering Company LLC (“T2 Eagle Ford”) and T2 LaSalle

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Gathering Company LLC (“T2 LaSalle”), operate natural gas pipelines. Prior to December 31, 2018, we owned a third joint venture with Targa, T2 EF Cogeneration Holdings LLC (“T2 Cogen”), which operates an electric cogeneration facility. We indirectly own a 50% interest in T2 Eagle Ford and a 25% interest in T2 La Salle, and prior to December 31, 2018, we indirectly owned a 50% interest in T2 Cogen.

We previously had a joint venture arrangement with T2 Cogen which operated a cogeneration facility next to our Lone Star plant with similar terms that we accounted for as an equity method investment. On December 31, 2018, Targa and the Partnership, as part of a settlement of previous disputes, agreed to terminate the T2 Cogen joint venture and distributed one cogeneration unit to Targa, while the Partnership received 100% interest in T2 Cogen. Therefore, as of the effective date of December 31, 2018, T2 Cogen was no longer accounted for as an equity method investment and was consolidated into the Partnership. In addition, under the terms of the settlement, T2 Eagle Ford and T2 LaSalle will now operate under the direction of Targa after the completion of a transition period. Our indirect ownership percentages will remain the same with respect to T2 Eagle Ford and T2 LaSalle, and therefore continue to be accounted for as equity method investments. The following table provides information regarding our pipeline joint venture investments, T2 Eagle Ford and T2 LaSalle, for the year ended December 31, 2018:

	As of December 31, 2018
Joint venture pipelines	Miles	Leased Capacity		Average throughput volumes of natural gas (MMcf/d)
Dimmit	49	50	%	20
LaSalle	63	25	%	111
Choke Canyon	72	50	%	137
Residue Header	76	50	%	226
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:

• 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.

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

South Texas

The assets in our South Texas region are located between Webb and Dimmit Counties near the Texas-Mexico border. As of December 31, 2018, these assets consisted of approximately 2,019 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 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 720 miles of pipeline, most of which is in Frio and LaSalle counties.

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, which is now owned by EPIC (as noted above in Recent Developments), 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 now EPIC, and mitigated the financial impact of the capacity reductions at Bonnie View. However, as a result of the completion of the Robstown sale, EPIC assumed all of the NGL purchase and sale agreements associated with Robstown, including those with the Partnership through December 31, 2019. Bonnie View will continue to serve as a backup option for EPIC to the extent Robstown is unable to fractionate our Y-grade product. In addition, EPIC has the option to request that the Partnership restart Bonnie View for the benefit of EPIC through December 31, 2019. At this time, we have no plans to restart Bonnie View and we will continue to operate the facility as a truck unloading facility and pipeline Y-grade receipt point.

Our Lone Star processing plant is a 300 MMcf/d cryogenic processing plant located in Bee County, Texas, and was acquired from TexStar 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 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.

Our Gregory cryogenic processing plant ("Gregory") was a cryogenic processing plant that we shut down in December 2016 and converted into a compressor station. The natural gas that previously was sent to Gregory was diverted to our newer, more efficient, Woodsboro plant.

Our Conroe processing plant and gathering system ("Conroe") was a 50 MMcf/d cryogenic natural gas plant that operated together to gather and process natural gas. Conroe was shut down in December 2016 and was dismantled as of December 31, 2017. 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.

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 582 miles of pipeline, ranging in

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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, 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.

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 40.9% of our revenue for the year ended December 31, 2018. 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, 2018 and 2017, we did not experience significant nonpayment for services. We had no allowance for uncollectible accounts receivable at December 31, 2018.

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.

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In regulations published November 20, 2018, PHMSA revised its pipeline safety rules governing plastic piping systems. These rules increase design factors, increase maximum pressure and diameter for certain types of pipe and components, and establish new standards for risers, among other changes. The requirements apply to new, repaired and replaced pipelines. We do not believe that compliance with these new regulations will have a material adverse effect upon our operations.

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 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

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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 February 1, 2019, in FERC Docket No. PR 19-35-000, Southcross Mississippi Pipeline, L.P. filed a petition for rate approval and amended statement of operating conditions in accordance with the required rate review. 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 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

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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 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

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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.

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.

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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 interrupt or diminish, in any material way, 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.

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

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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 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 has been and in the future 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 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 two 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. Both the stay and the underlying rules have been the subject of litigation. In September 2018, the EPA proposed revisions to the 2016 rules, which, according to the EPA, are intended to “streamline implementation, reduce duplicative EPA and state requirements, and significantly decrease unnecessary burdens on domestic energy producers.” ‎Future implementation of these standards is uncertain at this time. Compliance with the 2016 rules, if they are not stayed or significantly revised pursuant to EPA’s 2018 proposal, 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 was stayed nationwide by the U.S. Sixth Circuit Court of Appeals. 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.” Thereafter, the EPA and the Corps issued a final rule in January 2018 staying implementation of the 2015 rule for two years. On December 11, 2018, the EPA and the Corps proposed a new rule defining a narrower reach of the CWA’s jurisdiction. Given the nationwide patchwork of litigation and court rulings that have developed regarding the rules, the 2015 rule is effective in some states, while the agencies’ decision to delay implementation of the 2015 rule is effective in other states. If finalized, the 2018 proposed rule would apply nationwide, replacing the national patchwork of CWA jurisdictional applicability. Additionally, if finalized, it is possible that the 2018 proposed rule could be challenged. The scope of the CWA’s jurisdiction will likely remain fluid until a final regulatory determination is made and subsequent litigation, if any, is finalized. To the extent a rule ultimately promulgated or established, like the May 2015 rule, expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to permitting 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

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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. Both the stay and the underlying rules have been the subject of litigation. In September 2018, the EPA proposed revisions to the 2016 rules, which, according to the EPA, are intended to “streamline implementation, reduce duplicative EPA and state requirements, and significantly decrease unnecessary burdens on domestic energy producers.” ‎Future implementation of these standards is uncertain at this time. Compliance with the 2016 rules, if they are not stayed, or significantly revised pursuant to EPA’s 2018 proposal, 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 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. Such withdrawal has not yet been finalized, and it is not possible at this time to predict how or when the United States might ‎impose restrictions on GHGs as a result of the Paris Agreement. Further, several states and local ‎governments have stated their commitment to its principles in their effectuation of policy and regulations. We continue to monitor the international, state and local 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

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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 211 full-time employees as of December 31, 2018. 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. 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, you may also see the SEC website of such reports from the SEC's website at www.sec.gov.

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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. 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 Bankruptcy

The Partnership cautions that trading in the Partnership’s securities during the pendency of the Chapter 11 proceedings is highly speculative and poses substantial risks. Trading prices for the Partnership’s securities may bear little or no relationship to the actual recovery, if any, by holders of the Partnership’s securities in Chapter 11 proceedings.

We have filed voluntary petitions for relief under the Bankruptcy Code and are subject to the risks and uncertainties associated with bankruptcy cases.

On April 1, 2019, the Partnership and the Filing Subsidiaries filed voluntary petitions seeking relief under Chapter 11 of the Bankruptcy Code.

Our operations and ability to develop and execute our business plan, our financial condition, our liquidity and our continuation as a going concern, are subject to risks and uncertainties associated with our bankruptcy. These include, but are not limited to, the following:

• our ability to continue as a going concern;

• our ability to prosecute, confirm and consummate a plan of reorganization with respect to the Chapter 11 proceedings;

• our ability to obtain Bankruptcy Court, creditor and regulatory approval of a Chapter 11 plan of reorganization in a timely manner;

• our ability to obtain Bankruptcy Court approval with respect to motions in the Chapter 11 Cases and the outcome of Bankruptcy Court rulings and of the Chapter 11 Cases in general;

• the high costs of bankruptcy proceedings and related fees;

• the ability of third parties to seek and obtain Bankruptcy Court approval to terminate contracts and other agreements with us or to file motions in our Chapter 11 Cases, which may interfere with our business operations and our ability to propose and/or complete a Chapter 11 plan of reorganization;

• our ability to maintain normal payment and other terms with customers, vendors and service providers, as well as our ability to maintain contracts that are critical to our operations;

• a loss of, or a disruption in the materials or services received from suppliers, contractors or service providers with whom we have commercial relationships;

• our ability to obtain sufficient financings to allow us to emerge from bankruptcy and execute our business plan post emergence;

• potential increased difficulty in retaining and motivating our key employees through the process of reorganization, and potential increased difficulty in attracting new employees;

• significant time and effort required to be spent by our senior management in dealing with the bankruptcy and restructuring activities rather than focusing exclusively on business operations; and

• our ability to fund and execute our business plan and our ability to obtain necessary financing for our business on acceptable terms or at all.

We are also subject to risks and uncertainties with respect to the actions and decisions of creditors and other third parties who have interests in our Chapter 11 Cases that may be inconsistent with our plans. These risks and uncertainties could affect our business and operations in various ways and may significantly increase the duration of the Chapter 11 Cases. For example, negative events or publicity associated with the Chapter 11 Cases could adversely affect our relationships with our vendors and

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employees, as well as with customers, which in turn could adversely affect our operations and financial condition. Also, pursuant to the Bankruptcy Code, we need Bankruptcy Court approval for transactions outside the ordinary course of business, which may limit our ability to respond timely to events or take advantage of opportunities.

Because of the risks and uncertainties associated with the Chapter 11 Cases, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 Cases may have on our business, cash flows, liquidity, financial condition and results of operations, nor can we predict the ultimate impact that events occurring during the Chapter 11 Cases may have on our partnership or capital structure.

Our business could suffer from a long and protracted restructuring.

Our future results are dependent upon the successful confirmation and implementation of a Chapter 11 plan of reorganization or other alternative transaction, including a sale of all or substantially all of the Partnership’s assets. A long period of operations under Bankruptcy Court protection could have a material adverse effect on our business, financial condition, results of operations, liquidity and suppliers, customers and other counterparties may not want to do business with us while we are in bankruptcy. Failure to obtain confirmation of a Chapter 11 plan of reorganization or approval and consummation of an alternative transaction in a timely manner may harm our ability to finance adequately our operations, and there is a significant risk that the value of the Partnership would be substantially eroded to the detriment of all stakeholders. If a Chapter 11 plan or reorganization that complies with the applicable provisions of the Bankruptcy Code cannot be confirmed, it is possible that we would have to liquidate our assets, in which case it is likely that holders of claims would receive substantially less favorable treatment than they would receive if we were to emerge as a viable, reorganized entity.

For as long as the Chapter 11 Cases continue, we will be required to incur substantial costs for professional fees and other expenses associated with the administration of the Chapter 11 Cases. We are seeking Bankruptcy Court approval of DIP Financing to fund operations. If we are unable to obtain such financing on favorable terms or at all, our chances of successfully reorganizing our business may be seriously jeopardized, the likelihood that we instead will be required to liquidate our assets may be enhanced, and, as a result, any securities in us could become further devalued or become worthless.

There can be no assurance that we will successfully reorganize and emerge from the Chapter 11 Cases or, if we do successfully reorganize, as to when we would emerge from the Chapter 11 Cases.

Even if a Chapter 11 plan is confirmed and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders, suppliers and other counterparties to do business with a company that recently emerged from bankruptcy proceedings.

We have substantial liquidity needs and may be required to seek additional financing. If we are unable to maintain adequate liquidity, we may not be able to obtain financing on satisfactory terms.

Our principal sources of liquidity historically have been cash generated from operations, cash raised through issuances of additional debt securities and borrowings under our Senior Credit Facilities. Our capital program for 2019 will require additional financing above the level of cash generated by our operations. As described above, we filed a motion seeking entry of an order authorizing the Debtors to enter into the DIP Financing, but we cannot guarantee that the funds will be available under the DIP Financing and our cash flow from operations will be sufficient to fund our operations if we experience a prolonged bankruptcy.

We face uncertainty regarding the adequacy of our liquidity and capital resources and have extremely limited, if any, access to additional financing. In addition to the cash requirements necessary to fund ongoing operations, the Partnership has incurred significant professional fees and other costs in connection with preparation for the Chapter 11 Cases and expects that it will continue to incur significant professional fees and costs throughout the Chapter 11 Cases. We cannot assure you that cash on hand and cash flow from operations will be sufficient to continue to fund our operations and allow us to satisfy our obligations related to the Chapter 11 Cases if and until we are able to emerge from the Chapter 11 Cases.

Our liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to comply with the terms and conditions of any debtor-in-possession order entered by the Bankruptcy Court in connection with the Chapter 11 Cases, (ii) our ability to maintain adequate cash on hand, (iii) our ability to generate cash flow from operations, (iv) our ability to develop, confirm and consummate a Chapter 11 plan or other alternative restructuring transaction, and (v) the cost, duration and outcome of the Chapter 11 Cases. Our ability to maintain adequate liquidity depends in part upon industry conditions and general economic, financial, competitive, regulatory and other factors beyond our control. In the event that the possible DIP Financing and our cash on hand and cash flow from operations are not sufficient to meet our liquidity needs, we may be required to seek additional financing. We can provide no assurance that additional financing would be available or, if available, offered to us on acceptable terms. Our access to additional financing is, and for the foreseeable

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future will likely continue to be, extremely limited if it is available at all. Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time.

Even if a Chapter 11 plan of reorganization is consummated, we will continue to face risks.

Even if a Chapter 11 plan of reorganization is consummated, we will continue to face risks, including certain risks that are beyond our control, such as further deterioration or other changes in economic conditions, changes in our industry, changes in prices for oil and natural gas and increasing expenses. Some of these concerns and effects typically become more acute when a case under the Bankruptcy Code continues for a protracted period without indication of how or when the case may be completed. As a result of these risks and others, there is no guaranty that any plan of reorganization will achieve our stated goals.

Furthermore, even if our debts are reduced or discharged through a plan of reorganization, we may need to raise additional funds through public or private debt or equity financing or other means to fund our business after the completion of the Chapter 11 process. Adequate funds may not be available when needed or may not be available on favorable terms.

The terms of our indebtedness include restrictions and financial covenants that may restrict our business and financial activities.

The availability of borrowings under our DIP Financing is essential to our ability to fund our operations during the Chapter 11 Cases.

If we violate any provisions of our DIP Financing that are not cured or waived within the appropriate time periods provided therein, our DIP Financing may become immediately due and payable and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make any accelerated payments.

In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.

Upon a showing of cause, the Bankruptcy Court may convert our Chapter 11 case to a case under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under Chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in our Plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations.

We may be subject to claims that will not be discharged in the Chapter 11 proceedings, which could have a material adverse effect on our financial condition and results of operations.

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose prior to confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization and/or (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the plan of reorganization. Any claims not ultimately discharged through a plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.

Our financial results may be volatile and may not reflect historical trends.

During the Chapter 11 proceedings, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities and expenses, contract terminations and rejections, and claims assessments occur, which may significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of the bankruptcy filing.

In addition, if we emerge from Chapter 11, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to a plan of reorganization. We also may be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets

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and liabilities on our consolidated balance sheets. Our financial results after the application of fresh start accounting also may be different from historical trends.

Any Partnership de-levering transaction or change in the Partnership capital structure, including in connection with a plan of reorganization in the Chapter 11 proceedings, may involve significant taxable cancellation-of-debt or other income, such that the Partnership’s unitholders may be required to pay taxes on their share of such income even if they do not receive any cash distributions from the Partnership.

The Partnership’s unitholders, as the owners of the Partnership, are allocated the taxable income (or loss) of the Partnership for income tax purposes. Each unitholder is required to report its share of the Partnership’s taxable income on its federal and applicable state and local income tax returns. Accordingly, depending on their individual tax position, each unitholder may be required to pay income taxes on its share of the Partnership’s taxable income, even if the unitholder receives no cash distributions from the Partnership, which could happen.

Any restructuring transactions, including pursuant to the Chapter 11 proceedings are intended to be structured in a manner that minimizes, to the extent possible, any negative tax impact to the Partnership’s existing unitholders. Nevertheless, any transactions the Partnership may engage in to de-lever the Partnership and manage its liquidity could result in the allocation of substantial taxable income to the Partnership’s unitholders without any corresponding cash distribution. For example, the Partnership may sell assets and use the proceeds to repay existing debt, in which case unitholders would be allocated any taxable income or gain resulting from the sale. Additionally, several provisions of the Internal Revenue Code can defer or disallow any losses that may otherwise be recognized as result of a transfer of assets under certain circumstances (such as, potentially, a transaction between related parties). Further, the Partnership may pursue other opportunities to reduce its existing debt, such as exchanges, repurchases, modifications or extinguishment of Partnership debt that could result in cancellation-of-debt income being allocated to the Partnership’s unitholders as ordinary taxable income. It is possible that the income tax liability resulting from the allocation of such cancellation-of-debt or other income, if any, to a unitholder could exceed the current value of the unitholder’s investment in the Partnership. The ultimate effect of an allocation of cancellation-of-debt income to a unitholder will depend on the unitholder’s individual tax position, including, for example, the availability of any current or prior-year “suspended” passive losses to offset all or a portion of the allocable cancellation-of-debt income.

We cannot provide any assurance that any of the various options that we, along with our legal and financial advisors, are evaluating to mitigate any potential allocation of taxable income to unitholders upon a de-levering transaction or other change in the Partnership capital structure will be achieved or will be optimal for unitholders. Unitholders are encouraged to consult their tax advisors with respect to the consequences to them of any such transactions.

We may experience increased levels of employee attrition as a result of the Chapter 11 proceedings.

As a result of the Chapter 11 proceedings, we may experience increased levels of employee attrition, and our employees likely will face considerable distraction and uncertainty. A loss of key personnel or material erosion of employee morale could adversely affect our business and results of operations. Our ability to engage, motivate and retain key employees or take other measures intended to motivate and incentivize key employees to remain with us through the pendency of the Chapter 11 proceedings is limited by restrictions on implementation of incentive programs under the Bankruptcy Code. The loss of services of members of our senior management team could impair our ability to execute our strategy and implement operational initiatives, which would be likely to have a material adverse effect on our financial condition, liquidity and results of operations.

During the existence of an event of default and the Chapter 11 Cases, we have no borrowing capacity under our Senior Credit Facilities. Unless we are able to successfully restructure our existing indebtedness we may not be able to continue as a going concern.

Over the periods presented in the accompanying financial statements, our growth has been funded through a combination of borrowings under our Senior Credit Facilities and cash flows from operating activities. We currently have limited access to additional capital. During the existence of an event of default, we have no availability under our Senior Credit Facilities.

The accompanying consolidated financial statements have been prepared on a going concern basis which contemplates continuity of operations, realization of assets and liquidation of liabilities in the ordinary course of business. As a result of losses incurred, there is no assurance that the carrying amounts of assets will be realized or that liabilities will be settled for the amounts recorded. Unless we are able to successfully restructure our existing indebtedness under the Chapter 11 Cases we may not be able to continue as a going concern. There can be no assurance that the plan of reorganization will be confirmed by the Bankruptcy Court and consummated.

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Risks Related to Our Business

Our leverage may limit our ability to borrow additional funds, comply with the terms of our indebtedness or capitalize on business opportunities.

As of December 31, 2018, we had total principal indebtedness of $527.1 million, comprised of $429.1 million related to our term loan and $81.1 million (excluding outstanding letters of credit) related to our revolving credit facility and $16.9 million related to the Investment Notes (defined in Note 6 to our consolidated financial statements). Our substantial indebtedness could have important consequences to you. Because of our substantial indebtedness:

• our ability to engage in acquisitions without raising additional equity or obtaining additional debt financing is limited;

• our ability to obtain additional financing for working capital, capital expenditures, acquisitions, debt service requirements or other purposes and our ability to satisfy our obligations with respect to our indebtedness may be impaired in the future;

• a large portion of our cash flow from operations must be dedicated to the payment of principal and interest on our indebtedness, thereby reducing the funds available to us for other purpose;

• it may be more difficult for us to satisfy our obligations to our creditors, resulting in possible defaults on, and acceleration of, such indebtedness;

• we may be more vulnerable to general adverse economic and industry conditions;

• we may be at a competitive disadvantage compared to our competitors with proportionately less indebtedness or with comparable indebtedness on more favorable terms and, as a result, they may be better positioned to withstand economic downturns;

• our ability to refinance indebtedness may be limited or the associated costs may increase; and

• we may be prevented from carrying out capital spending and restructurings that are necessary or important to our growth strategy and efforts to improve operating margins of our businesses.

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, 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 current and any future indebtedness, we will be forced to take actions such as reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital, enter into restructuring transactions. We may not be able to effect any of these actions on satisfactory terms or at all.

We do 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 do 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. 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;

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• outages at the processing or NGL fractionation facilities owned by us or third parties, whether caused by mechanical failure resulting from maintenance, construction or otherwise;

• leaks or accidental releases of products or other materials into the environment, whether as a result of human error or otherwise;

• prevailing economic and market conditions;

• realized prices received for natural gas and NGLs;

• fixed-fees associated with our services;

• the market prices of natural gas and NGLs relative to one another, which affects our processing margins;

• capacity charges and volumetric fees associated with our transportation services;

• the level of competition from other midstream energy companies in our geographic markets;

• the level of our operating, maintenance, general and administrative costs;

• regulatory action affecting the supply of, or demand for, natural gas, the maximum transportation rates we can charge on our pipelines, our existing contracts, our operating costs or our operating flexibility; and

• the financial health of our parent company and its ability to pay amounts owed to us on a timely basis.

In addition, the actual amount of cash we will have depends 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;

• other business risks affecting our cash levels; and

• the occurrence of cyber security incidents resulting in information theft, data corruption, operational disruption and/or financial loss.

We expect to have a substantial customer concentration, with a limited number of customers accounting for a substantial portion of our revenues as a result of Holding' sale of its Robstown fractionation facility and our affiliate contracts with Holdings.

We expect to derive a significant portion of our revenues from EPIC Y-grade, the purchaser of Robstown, and successor to Holdings' obligations pursuant to the Robstown Purchase Agreement. EPIC Y-grade is expected to account for more than 30% of our revenues in 2019. There are inherent risks whenever a large percentage of total revenues are concentrated with a limited number of customers. If EPIC Y-Grade would experience declining financial position due to market, economic or competitive conditions, we could be pressured to reduce the fees we receive or have to accept payment terms which could have an adverse effect on our margins and financial position, and could negatively affect our revenues and results of operations and/or trading price of our units.

In addition, we have gathering and processing agreements with Holdings that govern the rates at which we charge Holdings to transport and process its natural gas and NGLs. For every MMBtu of natural gas production delivered to our system from the Lancaster or Valley Wells treating systems, Holdings must pay us fixed fees. In addition to the monthly fixed fees against physical volumes delivered, our intercompany gathering and processing contracts provide for quarterly and monthly minimum volume commitments ("MVC") at our Valley Wells treating facility. Under these MVC contracts, Holdings agrees to deliver to us 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. Holdings must make a shortfall payment to us at the end of the contracted

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measurement period if its actual throughput volumes are less than its MVC for that period. No production from the Lancaster gathering and treating system is subject to MVC commitments. The MVC contract with Holdings is expected to account for more than 10% of our revenues in 2019, as well as be a material source of our cash flow from operations in 2019 and April 2023 for our monthly MVC revenues, and July 2024 for our quarterly MVC revenues.

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.

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.

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

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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 and financial condition.

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. In addition, 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;

• 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.

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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.

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 the willingness of customers to accept the same index as a basis, physical differences in geography, product specifications and the ability to market products at the anticipated differential from the pricing index.

Unexpected volume changes due to production variability or to gathering, plant or pipeline system disruptions may increase our exposure to commodity price movements.

We sell processed natural gas to third parties at plant tailgates, pipeline pooling points or at inlet meters to the sites of industrial and utility customers. These sales may be interrupted by disruptions to volumes anywhere along the system. We attempt to balance sales with volumes supplied, but unexpected volume variations due to production variability or to gathering, plant or pipeline system disruptions may expose us to volume imbalances which, in conjunction with movements in commodity prices, could materially impact our income from operations and cash flow.

We may not successfully balance our purchases and sales of natural gas, which would increase our exposure to commodity price risks.

We purchase from producers and other suppliers a substantial amount of the natural gas that flows through our pipelines and processing facilities for sale to third parties, including natural gas marketers and others.

We are exposed to fluctuations in the price of natural gas through volumes sold pursuant to commodity-sensitive arrangements and, to a lesser extent, through volumes sold pursuant to our fixed-spread contracts.

In order to mitigate our direct commodity price exposure, we typically attempt to balance our natural gas sales with our natural gas purchases on an aggregate basis across all of our systems. We may not be successful in balancing our purchases and sales, and as such may become exposed to fluctuations in the price of natural gas. Our overall net position with respect to natural gas can change over time and our exposure to fluctuations in natural gas prices could materially increase, which in turn could result in increased volatility in our revenue, gross operating margin and cash flows.

Although we enter into back-to-back purchases and sales of natural gas in our fixed-spread contracts in which we purchase natural gas from producers or suppliers at receipt points on our systems and simultaneously sell a similar volume of natural gas at delivery points on our systems, we may not be able to mitigate all exposure to commodity price risks. Any of these actions could cause our purchases and sales to become unbalanced. If our purchases and sales are unbalanced, we will face increased exposure to commodity price risks, which in turn could result in increased volatility in our revenue, gross operating margin and cash flows.

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.

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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. In addition, certain of our contracts may be terminated as a result of the Chapter 11 process.

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 40.9% of our revenue for the year ended December 31, 2018. We have gathering, processing, transportation and/or sales contracts with each of these customers of varying duration and commercial terms. If we are unable to renew our contracts with one or more of these customers on favorable terms, we may not be able to replace any of these customers in a timely fashion, on favorable terms or at all. In addition, many of our customers are oil and gas companies that are facing liquidity constraints in light of the current commodity price environment and may be disproportionately affected by such constraints as compared to larger, better capitalized companies. This concentration of our customers in the energy industry may impact our overall exposure to credit risk as customers may be affected similarly by prolonged changes in economic and industry conditions. If a significant number of our customers experience a prolonged business decline or disruptions or enter into bankruptcy, we will incur increased exposure to credit risk and bad debts. Any material nonpayment or nonperformance by any of our key customers could have a material adverse effect on our revenue, gross operating margin, cash flows and our ability to make cash distributions to our unitholders. In any of these situations, our revenue, gross operating margin, cash flows and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to concentrated risk of nonpayment or nonperformance to continue as long as we remain substantially dependent on a relatively limited number of customers for a substantial portion of our revenue.

If third-party pipelines, other midstream facilities or purchasers of our products interconnected to our gathering or transportation systems become partially or fully unavailable, or if the volumes we gather, process or transport do not meet the natural gas and NGL quality requirements of such pipelines or facilities, our gross operating margin, cash flow and our ability to make distributions to our unitholders could be adversely affected.

Our natural gas gathering and transportation pipelines, NGL pipelines and processing and treating facilities connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of such third-party pipelines, processing plants, facilities of purchasers of our products and other midstream facilities is not within our control. These pipelines and facilities may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from natural disasters or other operational hazards. In addition, if the costs to us to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurred, if any of these pipelines or other midstream facilities become unable to receive, transport or process natural gas, or if the volumes we gather, process, treat or transport do not meet the natural gas quality requirements (such as hydrocarbon dew point, temperature and foreign content including water, sulfur, carbon dioxide and hydrogen sulfide) of such pipelines or facilities, our gross operating margin, cash flow and our ability to make cash distributions to our unitholders could be adversely affected.

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. In addition, portions of our pipeline systems are in public rights-of-way that may need to be moved or relocated from time to time at the request of government entities.  We may not be fully reimbursed for the expenses related to these relocations.

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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 not benefit from our acquisition strategy. 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.

As part of our business strategy, we regularly evaluate opportunities to enhance the value of the Partnership by pursuing acquisitions that increase our cash generated from operations on a per unit basis. Although we remain subject to financial and other covenants in our credit facilities that may limit our ability to pursue certain strategic opportunities, we intend to continue to evaluate and, when appropriate, pursue strategic acquisition opportunities as they arise. Furthermore, our bankruptcy may also limit our ability to pursue any acquisitions.

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 the terms of our indebtedness restrict us from making acquisitions, (iii) outbid by competitors or (iv) for any other reason, then our future growth could be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.

Any acquisition involves potential risks, including, among other things:

• mistaken assumptions about volumes, revenue and costs, including synergies;

• an inability to secure adequate customer commitments to use the acquired systems or facilities;

• the risk that natural gas reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;

• an inability to integrate successfully the assets or businesses we acquire, particularly given the relatively small size of our management team and their limited history with our assets;

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• 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.

We cannot provide any assurance, however, with respect to the timing, likelihood, size or financial effect of any potential transaction involving the Company, as we may not be successful in identifying and consummating any acquisition, particularly in light of our low liquidity levels, or in integrating any newly acquired business into our operations. Further, if we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

Our access to capital may be further limited due to deterioration of conditions in the global capital markets, weakening of macroeconomic conditions and negative changes in financial performance.

In general, we have relied, in large part, on banks and capital markets to fund our operations, contractual commitments and refinance existing debt. These markets can experience high levels of volatility and access to capital can be constrained for an extended period of time. In addition to conditions in the capital markets, a number of other factors, including our financial performance, substantial indebtedness 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 in the future 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.

Increases in interest rates could adversely impact our unit price and our ability to issue equity or incur debt for acquisitions or other purposes.

Interest rates on 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 the costs to us of any such issuance or incurrence.

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.

The terms of our indebtedness will include restrictions and financial covenants that may restrict our business and financing activities.

The operating and financial restrictions and covenants in any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions to our unitholders. Our future ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations and other events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of such financing

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agreements that are not cured or waived within the appropriate time periods provided therein, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions to our unitholders will be inhibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our revolving credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our revolving credit facility, the lenders could seek to foreclose on our assets.

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. We expect any future financing arrangements to be at least as restrictive as our revolving credit facility. 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.

On August 10, 2018, we entered into the Sixth Amendment (the "Sixth Amendment") to the Third A&R Revolving Credit Agreement which, among other things, reduced the Consolidated Interest Coverage Ratio from 1.50 to 1.00 to 1.25 to 1.00 for the period ending on June 30, 2018. The Sixth Amendment, notwithstanding, absent continued access to equity cures from our Sponsors or a significant equity infusion from a third party, or absent additional amendments to the Third A&R Revolving Credit Agreement (which matures on August 4, 2019) or waivers of the March 31, 2019 requirement to comply with the Consolidated Total Leverage Ratio and minimum Adjusted EBITDA (both as defined in the Fifth Amendment) and Consolidated Interest Coverage Ratio (as defined in the Sixth Amendment), the Partnership is not expected to comply with such financial covenants in the next twelve months, which will trigger an event of default under the Senior Credit Facilities. As a result, we have classified all of our debt as current as of December 31, 2018. See Notes 2 and 6 to our consolidated financial statements.

A failure to comply with the provisions of our revolving credit facility will 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 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;

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• 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.

We continually monitor the capital markets and our capital structure and may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening our balance sheet, meeting our debt service obligations and/or achieving cost efficiency. Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our indebtedness could cause us to incur high transaction costs, may be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments, including our revolving credit facility, may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our debt instruments restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due.

We can provide no assurances that any alternative strategic action or financing plan undertaken, including the proposed DIP Financing, will be successful in allowing us to meet our debt obligations or will result in additional liquidity. Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing could materially and adversely affect our ability to make payments on our indebtedness and our business, financial condition, results of operations and cash flows.

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

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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 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. Both the stay and the underlying rules have been the subject of litigation. In September 2018, the EPA proposed revisions to the 2016 rules, which, according to the EPA, are intended to “streamline implementation, reduce duplicative EPA and state requirements, and significantly decrease unnecessary burdens on domestic energy producers.” ‎Future implementation of these standards is uncertain at this time. Compliance with the 2016 rules, if they are not stayed, or significantly revised pursuant to EPA's 2018 proposal, 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. Such withdrawal has not yet been finalized, and it is not possible at this time to predict how or when the United States might ‎impose restrictions on GHGs as a result of the Paris Agreement. Further, several states and local ‎governments have stated their commitment to its principles in their effectuation of policy and regulations. We continue to monitor the international, state and local efforts to address climate change. To the extent the United States and other countries implement this agreement or impose other climate change regulations on the oil and gas industry, it could have an adverse direct or indirect effect on our business.

Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher 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 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

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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

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 our business strategies relates to 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.

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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 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

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• 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 $0.8 million and $0.9 million during the years ended December 31, 2018 and 2017, 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 2018 and 2017 testing programs.

Should we fail to comply with DOT or comparable state regulations, we could be subject to penalties and fines. Additionally, pipeline safety reforms, including new requirements, enhanced penalties and changes in the administration and enforcement of safety laws have been implemented in recent years and the consideration of additional reforms is ongoing. Such legislative and regulatory changes could have a material effect on our operations and costs of transportation service.

The implementation of statutory and regulatory requirements for derivative transactions could increase the costs and have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") was enacted in 2010 and amended the Commodity Exchange Act. This law regulates derivative and commodity transactions, including crude oil and gas hedging transactions used in our risk management activities. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”) and other regulators to promulgate rules and regulations implementing the new legislation. While many of the regulations have been promulgated and are already in effect, the rulemaking and implementation process is still ongoing, and we cannot yet predict the ultimate effect of the rules and regulations on our business.

In its rulemaking under the Dodd-Frank Act, the CFTC will likely finalize regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, although certain bona fide hedging transactions would be exempt from these position limits provided that various conditions are satisfied. Once finalized, the position limits rule and its companion rule on aggregation may have an impact on our ability to hedge our exposure to certain enumerated commodities.

The Dodd-Frank Act provisions are also intended to change fundamentally the way swap transactions are entered into, transforming an over-the-counter market in which parties negotiate directly with each other into a regulated market in which many swaps are to be executed on registered exchanges or swap execution facilities and cleared through central counterparties. To date, several categories of interest rate and index credit default swaps have been designated by the CFTC as mandatorily clearable swaps. These swaps may also be required to be traded on registered swap execution facilities or exchanges. Both the clearing and the trading requirements are likely to increase significantly transaction costs of entering into swaps (e.g., by entering into agreements with and paying commission to brokerage and clearing intermediaries). Even if we chose to rely on the end-user exception from the clearing and trading requirements, we would be required to take certain steps to qualify for the end-user exception. As the CFTC further designates swap contracts as required to be cleared and traded on a trading facility, the utility of the end-user exception will become even more important. Our ability to rely on the end-user exception may change the profitability of our trades or the efficiency of our hedging.

The Dodd-Frank Act and any new regulations could, among other things, significantly increase the cost of entering into derivative and commodity contracts (including from swap record-keeping and reporting requirements), materially alter the terms of derivative contracts, reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, require greater collateral support for derivative contracts and potentially increase our exposure to less creditworthy counterparties.  If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable. Any of these consequences could have a material adverse effect on our financial condition, results of operations and cash available for distribution to unitholders.

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.

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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.

Cyber-attacks, acts of terrorism or other disruptions could adversely impact our results of operations and our ability to make cash distributions to unitholders.

We are subject to cyber security risks related to breaches in the systems and technology that we use (i) to manage our operations and other business processes and (ii) to protect sensitive information maintained in the normal course of our businesses. The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain processing activities. For example, we depend on digital technologies to perform many of our services and to process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we will likely be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks.

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

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prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”), but our internal accounting controls may not meet all standards applicable to companies with publicly traded securities. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, or Sarbanes-Oxley, which we refer to as Section 404.

Given the difficulties inherent in the design and operation of internal controls over financial reporting, in addition to our limited accounting personnel and management resources, we can provide no assurance as to our or our independent registered public accounting firm’s future conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Any failure to implement and maintain effective internal controls over financial reporting will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

We are required to disclose changes made in our internal control and procedures on a quarterly basis and make an annual assessment of our internal control over financial reporting pursuant to Section 404 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.

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 (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. Although our General Partner has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our General Partner also have a duty to manage our General Partner in a manner that is beneficial to its ultimate owner, Holdings. Conflicts of interest may arise between Holdings and our General Partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our General Partner may favor its own interests and the interests of Holdings over our interests and the interests of our unitholders. These conflicts include the following situations, among others:

• Neither our Third Amended and Restated Agreement of Limited Partnership (“Partnership Agreement”) nor any other agreement requires Holdings to pursue a business strategy that favors us.

• Our General Partner is allowed to take into account the interests of parties other than us, such as Holdings, in resolving conflicts of interest.

• Our Partnership Agreement replaces the fiduciary duties that would otherwise be owed by our General Partner to us and our unitholders with contractual standards governing its duties to us and our unitholders, limits our General Partner’s liabilities, and also restricts the rights of our unitholders with respect to actions that, without the limitations, might constitute breaches of fiduciary duty.

• Except in limited circumstances, our General Partner has the power and authority to conduct our business without unitholder approval.

• Our General Partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

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• Our General Partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or a growth capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our General Partner and the ability of the subordinated units to convert to common units.

• Our General Partner determines which costs incurred by it are reimbursable by us.

• Our General Partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.

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

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

• Our General Partner has limited its liability regarding our contractual and other obligations.

• Our General Partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.

• Our General Partner controls the enforcement of the obligations that it and its affiliates owe to us.

• Our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.

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

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.

Our General Partner has limited its liability regarding our obligations.

Our General Partner has limitedits 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.

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 March 20, 2019, Holdings, the 100% owner of our General Partner, owned, indirectly, 54.4% 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 March 20, 2019, Holdings indirectly owns an approximate 72.6% limited partner interest in us. Also, if our General Partner is removed without cause during the subordination period and units held by our General Partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our General Partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our General Partner liable for actual fraud or willful misconduct in its capacity as our General Partner. Cause does not include most cases of charges of poor management of the business, so the removal of our General Partner because of the unitholder’s dissatisfaction with our General Partner’s performance in managing us will most likely result in the termination of the subordination period and the conversion of all subordinated units to common units

Our Partnership Agreement restricts the voting rights of unitholders owning 20% or more of our common units.

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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.

We may issue additional units without your approval, which would dilute your existing ownership interests.

Our Partnership Agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

• our existing unitholders' proportionate ownership interest in us will decrease;

• the amount of cash available for distribution on each unit may decrease;

• because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

• the ratio of taxable income to distributions may increase;

• the relative voting strength of each previously outstanding unit may be diminished; and

• the market price of the common units may decline.

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 March 20, 2019, Holdings held an aggregate of 26,492,074 common units, 12,213,713 subordinated units and 19,996,781 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 March 20, 2019, Holdings owned 54.4% of our 48,694,891 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 72.6% of our outstanding common units.

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

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to our general partner. We are organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in

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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 have difficulty attracting, motivating and retaining executives and other employees.

Uncertainty concerning our ability to continue as a going concern on our employees may have an adverse effect on us. This uncertainty may impair our ability to attract, retain and motivate personnel. Employee retention and recruitment may be particularly challenging, 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 surrounding our ability to continue as a going concern or a desire not to remain with us, our results of operations, financial condition, and cash flows could be adversely affected.

Risks Related to our Common Units

As a result of the delisting of our common units on NYSE, our common units are currently traded on the OTCQX and will trade indefinitely on one of the other over-the-counter markets, which could adversely affect the market liquidity of our common units and harm our business.

On February 27, 2019, the NYSE notified us that the NYSE Regulation had determined to commence proceedings to delist our common units from the NYSE due to our continued non-compliance with the continued listing standard set forth in Section 802.01C of the NYSE Listed Company Manual, which requires the average closing price of the Partnership’s common units to be at least $1.00 per unit over a consecutive 30 trading-day period. As a result, the NYSE suspended trading of our common units at the close of trading on February 27, 2019 and our common units were delisted from the NYSE on April 1, 2019. On February 28, 2019, our common units began trading on the OTCQX Market (the "OTCQX"), which is operated by OTC Markets Group, Inc., under the trading symbol “SXEE”.

The OTCQX is an over-the-counter market that is a significantly more limited market than the NYSE. Securities traded on the OTC markets are usually thinly traded, highly volatile, have fewer market makers and are not followed by analysts. Trading on the OTCQX or one of the other over-the-counter markets may result in a reduction in some or all of the following, each of which could have a material adverse effect on our unitholders:

• the volume and liquidity of our common units;

• the market price of our common units;

• our ability to raise additional financing through public or private sales of equity securities or obtain other financing;

• the number of institutional and other investors that will consider investing in our common units;

• the number of market makers in our common units;

• the availability of information concerning the trading prices and volume of our common units; and

• the number of broker-dealers willing to execute trades in our common units.

Further, since our common units were delisted from the NYSE, we are subject to fewer rules and regulations, including with respect to corporate governance, than if our common units were traded on the NYSE. Without required compliance of these corporate governance standards, investor interest in our common units may decrease.

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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.

The market price of our common units may fluctuate significantly, and you could lose all or part of your investment.

There were 22,194,141 publicly traded common units as of December 31, 2018. In addition, Holdings owned 26,492,074 common units, 12,213,713 subordinated units and 19,652,831 Class B Convertible Units as of December 31, 2018. 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.

Our common units trade on the OTCQX but an active trading market for our common units may not be sustained. The market price of our common units may decline and be influenced by many factors, some of which are beyond our control, including:

• bankruptcy proceedings and the outcome of the Chapter 11 process;

• 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."

Many of these factors are beyond our control and we cannot predict their potential effects on the price of our common units. In addition, the stock markets in general can experience considerable price and volume fluctuations. See further discussion of the impact of the Chapter 11 proceedings on our common units in Item “1A. Risk Factors - We believe it is highly likely that our existing common units will be canceled at the conclusion of our Chapter 11 proceedings.”

Our common unit price has reflected a great deal of volatility, including a significant decrease over the past few years. The volatility may mean that, at times, our unitholders may be unable to resell their shares at or above the price at which they acquired them.

From January 1, 2017 through February 27, 2019, the price per share of our common stock has ranged from a high of $4.64 to a low of $0.22. The price of our common units has been, and may continue to be, highly volatile and subject to wide fluctuations. The market value of our common units has declined in the past, in part, due to our operating performance as well as other factors. In the future, broad market and industry factors may decrease the market price of our common units, regardless of our actual operating performance. Recent declines in the market price of our common units have and could continue to affect our access to capital, and may, if they continue, impact our ability to continue operations at the current level. In addition, any continuation of the recent declines in the price of our common units may curtail investment opportunities presented to us, and negatively impact other aspects of our business, including our ability to raise the funds necessary to fund our operations. As a result of any such declines, many unitholders have been or may become unable to resell their common units at or above the price at which they acquired them.

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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.

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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 adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be reduced. These rules are not applicable to us for tax years beginning on or prior to December 31, 2017.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If our unitholders sell common units, they will recognize gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units they sell will, in effect, become taxable income to them if they sell such common units at a price greater than their tax basis in those common units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized on any sale of their common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if our unitholders sell their common units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investments in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, is unrelated business taxable income and is taxable to them. Distributions to non-U.S. persons are reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons are required to file federal income tax returns and pay tax on their share of our taxable income.

We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from their sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns.

We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge aspects of our proration method, and, if successful, we would be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The U.S. Department of Treasury and the IRS recently issued Treasury regulations that permit publicly traded partnerships to use a monthly simplifying convention that is similar to ours, but they do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to successfully challenge this method, we could be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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A unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units. If so, such unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income.

We have adopted certain valuation methodologies in determining a unitholder's allocation of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of the common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, in certain circumstances, including when we issue additional units, we must determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

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.

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

On April 1, 2019, the Partnership, General Partner and the Filing Subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Chapter 11 Cases are being jointly administered for procedural purposes only by the Bankruptcy Court under the caption In re Southcross Energy Partners, L.P., et al, Case No. 19-10702. As a result of the Chapter 11 Cases, attempts to prosecute, collect, secure or enforce remedies with respect to pre-petition claims against the Debtors are subject to the automatic stay provisions of Section 362(a) of the Bankruptcy Code, including litigation relating to the entities involved in the Chapter 11 Cases. See Note 14 to our consolidated financial statements for additional information.

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

As of March 20, 2019, there were 4 holders of record, approximately 3,799 beneficial owners of our common units and 48,694,891 common units outstanding. As of March 20, 2019, we have issued 12,213,713 subordinated units, 19,996,781 Class B Convertible Units and 1,651,130 general partner units, for which there is no established trading market.

Our common units have historically been traded on the NYSE. On February 27, 2019, the NYSE suspended the trading of our common units and commenced proceedings to delist our common units due to our continued non-compliance with Section 802.01C of the NYSE Listed Company Manual which requires that the average closing price of the Partnership’s common units to be at least $1.00 per unit over a consecutive 30 day-trading period. Effective February 28, 2019, our common units commenced trading on the OTCQX Marketplace under the symbol “SXEE”.

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.

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 formed in April 2012. 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, one treating 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 (the "Class B Convertible Units") and currently owns 54.4% of our common units. Our General Partner owns an approximate 2.0% interest in us and all of our incentive distribution rights. 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 Holdings' former term loan lenders own the remaining one-third of Holdings.

Chapter 11 Cases

On April 1, 2019 (the "Petition Date"), the Partnership and certain of the Partnership's subsidiaries, including Southcross Energy Partners, L.P., our General Partner, Southcross Energy Finance Corp., Southcross Energy Operating, LLC, Southcross Energy GP LLC, Southcross Energy LP LLC, Southcross Gathering Ltd., Southcross CCNG Gathering Ltd., Southcross CCNG Transmission Ltd., Southcross Marketing Company Ltd., Southcross NGL Pipeline Ltd., Southcross Midstream Services, L.P., Southcross Mississippi Industrial Gas Sales, L.P., Southcross Mississippi Pipeline, L.P., Southcross Gulf Coast Transmission Ltd., Southcross Mississippi Gathering, L.P., Southcross Delta Pipeline LLC, Southcross Alabama Pipeline LLC, Southcross Nueces Pipelines LLC, Southcross Processing LLC, FL Rich Gas Services GP, LLC, FL Rich Gas Services, LP, FL Rich Gas Utility GP, LLC, FL Rich Gas Utility, LP, Southcross Transmission, LP, T2 EF Cogeneration Holdings, LLC, and T2 EF Cogeneration LLC (collectively the “Filing Subsidiaries” and, together with the Partnership and General Partner, the “Debtors”) filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). The Debtors’ have proposed to jointly administer their Chapter 11 cases under the caption In re Southcross Energy Partners, L.P., Case No. 19-10702 (the “Chapter 11 Cases”). We will continue to operate our businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The Debtors have filed with the Bankruptcy Court motions seeking a variety of first-day relief, which are designed primarily to minimize the impact of the Chapter 11 proceedings on our operations, customers and employees and includes a motion to obtain post-petition financing. We expect to continue our operations without interruption during the pendency of the Chapter 11 proceedings.

On April 1, 2019, we filed a motion seeking entry of an order authorizing the Debtors to enter into the Debtor-in-Possession financing (“DIP Financing”) to, among other things, provide additional liquidity to fund our operations during the Chapter 11 process.

Pursuant to a Commitment Letter dated as of March 31, 2019 and Form Credit Agreement attached thereto (the “DIP Credit Agreement” and, the facility thereunder, the “DIP Facility”), to be entered into by  Southcross, as borrower, its direct and indirect Debtor subsidiaries, as guarantors (the “Guarantors” and, together with Southcross, the “Loan Parties”), certain of our creditors under the Senior Credit Facilities, as lenders (the “DIP Lenders”) and letter of credit issuers (the “DIP L/C Issuers”), and Wilmington Trust, National Association, as administrative agent (the “DIP Agent”), the DIP Lenders have agreed to provide to the Loan Parties the DIP Financing in an aggregate principal amount of $255 million, consisting of (i) a senior secured priming superpriority term loan in the aggregate principal amount of $72.5 million (the “DIP New Money Loan”), (ii) a senior secured priming superpriority term loan in the aggregate principal amount of $55 million (the “DIP LC Loan” and, together

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with the DIP New Money Loans, the “DIP Term Loans”) to cash collateralize a letter of credit sub-facility for the issuance of letters of credit by certain issuing banks that will be party to the DIP Credit Agreement (the “DIP L/C Facility”), and (iii) a senior secured priming superpriority term loan in the aggregate principal amount of $127.5 million, which will be subject and subordinate to the DIP New Money Facility and the DIP L/C Facility, to refinance dollar-for-dollar term loans outstanding under the Term Loan Agreement owed to the DIP Lenders (the “DIP Roll-Up Loan” and, together with the DIP Term Loans, the “DIP Loans”). The DIP Loans are subject to approval by the Bankruptcy Court.  The proceeds of the DIP Loans will be used for purposes permitted by the Bankruptcy Court and the DIP Credit Agreement, including (i) working capital and other general corporate purposes of the Loan Parties, including the refinancing of certain term loans and letters of credit, (ii) to pay transaction costs, professional fees, and other obligations and expenses incurred in connection with the DIP Facilities, the Chapter 11 Cases, and the transactions contemplated thereunder, and (iii) to make adequate protection payments to Southcross’s creditors under the Senior Credit Facilities to the extent set forth in any order entered by the Bankruptcy Court.

The DIP Facilities will mature on the earliest of (i) the date that is six months after the Petition Date (subject to one three month extension with the consent of the DIP Lenders constituting the required lenders under the DIP Facility), (ii) the effective date of a chapter 11 plan, (iii) the date on which all or substantially all of the assets of the Loan Parties are sold in a sale under a chapter 11 plan or pursuant to Section 363 of the Bankruptcy Code, and (iv) the date the DIP Facilities are accelerated following an event of default thereunder. Subject to certain exceptions, the DIP Facility will be secured by a senior perfected security interest in substantially all of the assets of the Loan Parties, including the collateral securing the Senior Credit Facilities and any other previously unencumbered assets.

We continue to engage in discussions with our creditors regarding the terms of a financial restructuring plan. In conjunction with this process, we will explore potential strategic alternatives to maximize value for the benefit of our stakeholders, which may include a sale of certain or substantially all of our assets under Section 363 of the Bankruptcy Code, a plan of reorganization to equitize certain indebtedness as an alternative to the sale process, or a combination thereof.

For the duration of the of the Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to significant risks and uncertainties associated with Chapter 11 proceedings. As a result of these significant risks and uncertainties, our assets, liabilities, unitholders’ equity (deficit), officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in these financial statements may not accurately reflect our operations, properties and capital plans following the Chapter 11 proceedings. See further discussion of the Chapter 11 proceedings in Note 14 to our consolidated financial statements.

Recent Developments

Delisting of Common Units from NYSE

On February 27, 2019, the New York Stock Exchange (“NYSE”) notified the Partnership that the staff of NYSE Regulation, Inc. (the “NYSE Regulation”) had determined to commence proceedings to delist our common units. The NYSE Regulation reached its decision to delist our common units pursuant to Rule 802.01C of the NYSE’s Listed Company Manual, as the Partnership’s unit price had fallen below the NYSE’s continued listing standard with average closing price of less than $1.00 over a consecutive 30 trading-day period and failed to cure this non-compliance within the required timeframe. The NYSE also suspended trading after the market close on the NYSE on February 27, 2019.

Effective February 28, 2019, our common units commenced trading on the OTCQX Marketplace under the ticker symbol "SXEE". On March 20, 2019, the NYSE filed with the SEC a notification of removal from listing and registration on Form 25 to delist our common units and terminate the registration of our common units under Section 12(b) of the Securities Exchange Act of 1934. The delisting became effective on April 1, 2019.

Holdings' Sale of Robstown Facility

On October 4, 2018, EPIC Midstream Holdings, LP (“EPIC”) and EPIC Y-Grade Holdings, LP, a subsidiary of EPIC,

entered into a definitive equity purchase agreement (the "Robstown Purchase Agreement") with Holdings and Holdings Borrower to acquire Holdings' Robstown fractionation facility ("Robstown") and related pipelines that enables Robstown to receive natural gas liquids from various supply sources and several short pipelines that allow the delivery of fractionated products to Corpus Christi-area markets. Under the terms of the agreement, EPIC assumed all of the NGL purchase and sale agreements associated with Robstown, including certain natural gas liquids sales and transportation agreements with the Partnership. The sale was completed in November 2018.

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Distribution Suspension

The board of directors of our General Partner (the "Partnership GP Board") suspended paying a quarterly distribution with respect to the fourth quarter of 2015 and every quarter of 2016, 2017 and 2018 to conserve any excess cash for the operation of our business and due to restrictions imposed by our debt instruments. See Notes 2 and 3 to our consolidated financial statements.

Liquidity Constraints

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, (i) the total aggregate commitments under the Third A&R Revolving Credit Agreement were reduced from $200 million to $115 million and the sublimit for letters of credit was also reduced from $75 million to $50 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 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 were required to maintain minimum levels of Consolidated EBITDA (as defined in the Fifth Amendment) on a quarterly basis and were 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 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 and Term Loan 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”).

On July 29, 2018, we terminated the Agreement and Plan of Merger, dated October 31, 2017, by and among us, our General Partner, American Midstream Partners, LP, a Delaware limited partnership (“AMID”), American Midstream GP, LLC, a Delaware limited liability company and the general partner of AMID (“AMID GP”), and Cherokee Merger Sub LLC, a Delaware limited liability company and wholly owned subsidiary of AMID (“Merger Sub”) as amended by that certain Amendment No. 1 to Merger Agreement, dated as of June 1, 2018, by and among us, our General Partner, AMID, AMID GP and Merger Sub (as amended, the “Merger Agreement”), since the transactions contemplated by the Merger Agreement was not completed on or prior to June 15, 2018. As previously disclosed, under the Merger Agreement, we were to merge with and into Merger Sub, with the Partnership surviving the merger as a wholly owned subsidiary of AMID.

On August 10, 2018, we entered into the sixth amendment (the “Sixth Amendment”) to the Third A&R Revolving Credit Agreement which, among other things, reduced the Consolidated Interest Coverage Ratio from 1.50 to 1.00 to 1.25 to 1.00 for the period ending on June 30, 2018. See Note 6 to our consolidated financial statements.

During management's ongoing assessment of the Partnership's financial forecast, the board of directors of Southcross Holdings GP, LLC (the “Holdings GP Board”) and the Partnership GP Board, together with our management, determined that in the then current corporate capital structure and absent continued access to equity cures from our Sponsors or a significant

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equity infusion from a third party, or absent additional amendments to its Third A&R Revolving Credit Agreement (which matures on August 4, 2019) or waivers of the March 31, 2019 requirement to comply with the Consolidated Total Leverage Ratio and minimum Adjusted EBITDA (both as defined in the Fifth Amendment) and Consolidated Interest Coverage Ratio (as defined in the Sixth Amendment), the Partnership was not expected to be able to comply with such financial covenants, which would have triggered an event of default under the Senior Credit Facilities. As a result of the Partnership’s expected inability to comply with its financial covenants within the twelve months from the issuance of this Annual Form 10-K, together with the maturity date of the Third A&R Revolving Credit Agreement being in less than twelve months, management determined that there are conditions and events that raise substantial doubt about the Partnership’s ability to continue as a going concern.

In March 2019, in light of (a) the August 4, 2019 maturity of the Third A&R Revolving Credit Agreement, (b) the

impending non-compliance with our Consolidated Total Leverage Ratio, minimum Adjusted EBITDA and Consolidated Senior

Secured Leverage Ratio (each as defined in the Fifth Amendment - see Note 2 and 6 to our consolidated financial statements) at March 31, 2019 that would result in an event of default under the Senior Credit Facilities, (c) our non-compliance with our minimum Adjusted EBITDA and Consolidated Interest Coverage Ratio as of December 31, 2018 (see Note 6 to our consolidated financial statements); and (d) the inclusion of a going concern uncertainty explanatory paragraph in the audit opinion on our consolidated financial statements, which constitutes an event of default under the Senior Credit Facilities, we elected not to make the approximately $7.4 million interest payment on our Term Loan that was due on March 29, 2019. While we have been in discussions with our creditors, those discussions did not produce an agreement prior to the Petition Date that would enable us to address effectively, in a holistic manner, the impending issues adversely impacting our business, including (i) impending maturity of the Third A&R Revolving Credit Agreement, (ii) current and potential near-term breaches of certain financial covenants, and (iii) certain other potential defaults under our Senior Credit Facilities.

Management Changes

Effective September 17, 2018, the Partnership GP Board elected James W. Swent III as the Chairman, President and Chief Executive Officer of our General Partner. Mr. Swent succeeded David W. Biegler, who stepped down as Chairman, President and Chief Executive Officer of the General Partner after serving as the acting Chairman, President and Chief Executive Officer of our General Partner when Bruce A. Williamson, stepped down from those positions for personal reasons in August 2018. Mr. Biegler continues to serve as a director on the Partnership GP Board.

Mr. Swent is the former Chairman of the Board, President and Chief Executive Officer of Paragon Offshore Limited from July 2017 to April 2018, a global supplier of offshore jack up contract drilling services. From July 2003 to December 2015, he was Executive Vice President and Chief Financial Officer of Ensco plc, a global provider of offshore contract drilling services. Mr. Swent holds a Bachelor of Science degree in Finance and a Master’s degree in Business Administration from the University of California at Berkeley.

Effective January 4, 2019, Michael B. Howe joined the General Partner as Senior Vice President and Chief Financial Officer. Mr. Howe succeeded Bret M. Allan, the former Senior Vice President and Chief Financial Officer of our General Partner who resigned from all positions with our General Partner effective January 4, 2019.

Prior to joining our General Partner, Mr. Howe served as Chief Financial Officer of Medical Benevolence Foundation and served in Christian ministries, including as a volunteer minister with the Texas Department of Criminal Justice, and worked for Ensco PLC (NYSE: ESV) during which time he served in various positions including, as Vice President - Strategy, Vice President - Human Resources, Vice President - Finance, and Treasurer. Mr. Howe holds a Bachelor of Science in Accounting from Oklahoma State University and a Master in Business Administration from the University of Texas at Austin. He is a Certified Public Accountant.

Effective February 1, 2019, the Partnership GP Board elected William C. Boyer as our General Partner’s Senior Vice President and Chief Operating Officer. Prior to being elected Senior Vice President and Chief Operating Officer of our General partner, Mr. Boyer served as Senior Vice President of Operations of the General Partner and as Vice President of Operations. Before joining our General Partner in 2015, Mr. Boyer served as General Manager of Oxy Midstream Operating Company (“Oxy”), a company specializing in midstream services of petroleum products, from 2014 to 2015. In his role at Oxy, Mr. Boyer oversaw the operations, safety, compliance and overall P&L for all of Occidental’s midstream businesses including Centurion Pipeline, its crude oil trucking, its NGL railcar terminal, and its propane and crude oil marine terminal businesses in Ingleside, Texas. Prior to joining Oxy, Mr. Boyer served as President of Centurion Pipeline where he led the operations, planning, risk management, safety and regulatory functions of the business. Concurrent with his role at Oxy, Mr. Boyer also served as President of Occidental Energy Transportation, a wholly-owned crude oil trucking subsidiary within Occidental Petroleum that gathered and transported crude oil in New Mexico and Texas. Mr. Boyer received a B.S. in Chemical Engineering from the University of Oklahoma.

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General Trends and Outlook

Our business environment and corresponding operating results are affected by key trends discussed below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results. Key trends that we monitor while managing our business include natural gas supply and demand dynamics overall and in our markets as well as growth production from U.S. shale plays, with specific attention on the Eagle Ford Shale region.

Natural Gas and NGL Environment

According to the U.S. Energy Information Administration (the “EIA”), 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 NGLs, 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 81.6 billion cubic feet per day (Bcf/d) in 2018, a 10% increase from 2017. Natural gas consumption is forecasted to increase by 1.1 Bcf/d in 2019 and by 0.9 Bcf/d in 2020. The largest natural gas consuming sector in the United States is the electric power sector. EIA estimates that electric generation consumed an average of 29.0 Bcf/d in 2018, up 14.4% from 2017 because of warmer summer temperatures in 2018 and the addition of natural gas-fired electric generation capacity. EIA forecasts power sector consumption of natural gas to remain largely unchanged in 2019 and then rise by 3.3% in 2020 because of continuing increases in natural gas-fired electric generation capacity.

In 2019, EIA expects residential and commercial natural gas consumption to average 13.4 Bcf/d and 9.3 Bcf/d, respectively, which are similar to consumption levels in 2018. Based on forecasts by the National Oceanic and Atmospheric Administration ("NOAA"), EIA forecasts 2019 heating degree days ("HDD") to be 1% lower compared with 2018. The cold weather in the first quarter of 2018 raised natural gas consumption higher than seasonal norms in the residential and commercial sectors in the Northeast. Natural gas consumption in the residential and commercial sectors is expected to decline by 2.2% and by 3.2%, respectively, in 2020. The forecast decline in 2020 reflects NOAA’s outlook for 1% fewer HDDs in 2020 compared with 2019.

EIA estimates that dry natural gas production will average 90.2 Bcf/d in 2019, an 8.3% increase from 2018 levels. In 2020, production is expected to increase by 2.2%, averaging 92.2 Bcf/d for the year. EIA’s expected growth in natural gas production is largely in response to improved drilling efficiency and cost reductions, higher associated gas production from oil-directed rigs, and increased takeaway pipeline capacity from the highly productive Appalachia and Permian production regions. Forecasted natural gas production growth is supported by planned expansions in liquefied natural gas (LNG) capacity and increased pipeline exports to Mexico.

The United States exported more natural gas than it imported in 2018, with net exports averaging 2.1 Bcf/d. Rising LNG exports and pipeline exports have contributed to a shift from the United States being a net importer of natural gas as recently as the first quarter of 2017. U.S. exports of natural gas, including exports to Mexico and Canada via pipeline and as LNG, averaged 10.0 Bcf/d in 2018. EIA forecasts that gross U.S exports will rise by 31.5% to 13.2 Bcf/d in 2019 and then by 15.1% to 15.2 Bcf/d in 2020.

EIA expects U.S. LNG exports to increase from an estimated 3.0 Bcf/d in 2018 to 5.1 Bcf/d in 2019 and to 6.8 Bcf/d in 2020, as three new liquefaction projects come online. EIA forecasts that U.S. LNG export capacity will almost double by the end of 2019 to 8.9 Bcf/d once new trains at Cameron LNG, Freeport LNG, and Elba Island LNG are commissioned, making U.S. LNG export capacity the third largest in the world behind Australia and Qatar. By mid-2020, EIA expects U.S. LNG export capacity to reach 9.6 Bcf/d once the third train at Freeport LNG comes online and to expand to 10.2 Bcf/d by mid-2020 once the third train at Corpus Christi LNG comes online.

U.S. natural gas exports to Mexico via pipeline have also increased as more infrastructure has been built to transport natural gas both to and within Mexico. U.S. pipeline exports to Mexico through October 2018 averaged 4.6 Bcf/d, increasing by 10% in 2018 compared with the same period in 2017. Exports to Mexico should continue to increase as more natural gas-fired power plants come online in Mexico and more pipeline infrastructure within Mexico is built.

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U.S. net natural gas pipeline imports from Canada decreased from 2017 to 2018. This decrease in net imports is expected to continue as Appalachian production growth displaces some Canadian natural gas imports in the U.S. Midwest markets.

Interest Rate Environment

In 2018, interest rates were increased by the Federal Reserve four times, which marks the seventh increase since March 2017, signaling that rates may continue to rise in 2019. The Federal Reserve expects that economic conditions will continue to evolve in a manner that will warrant gradual increases in interest rates two times again in 2019. The gradual increases could affect our ability to access the debt capital markets to the extent we may need to fund our growth in the future. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly.

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 transport to fractionation. 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-based 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-based price, plus or minus a fixed price differential. By entering into such back-to-back purchases and sales, we are able to mitigate our risk associated with changes in the general commodity price levels of natural gas and NGLs. We remain subject to variations in our fixed-spreads to the extent we are unable to precisely match volumes purchased and sold in a given time period or are unable to secure the supply or to produce or market the necessary volume of products at our anticipated differentials to the index price.

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

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

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(see Note 8 to our consolidated financial statements), fee based revenue increases with no associated cost of natural gas and NGLs sold. We enter into primarily fixed-fee and fixed-spread deals.

HowWe 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, gain on sale of assets 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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Reconciliations of Non-GAAP Financial Measures

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,
	2018			2017
Net cash provided by operating activities	$	15,652		$	26,182
Add (deduct):
Depreciation and amortization	(70,892		)	(71,902		)
Unit-based compensation	(219		)	(1,375		)
Amortization of deferred financing costs, original issuance discount and PIK interest	(5,542		)	(3,569		)
Gain on sale of assets, net	753			5
Unrealized gain (loss) on financial instruments	9			(2		)
Equity in losses of joint venture investments	(12,351		)	(13,060		)
Impairment of assets	(430,313		)	(1,769		)
Gain on insurance proceeds	—			1,508
Other, net	252			474
Changes in operating assets and liabilities:
Trade accounts receivable, including affiliates	(7,163		)	5,425
Prepaid expenses and other current assets	9,133			(829		)
Other non-current assets	(232		)	58
Accounts payable and accrued liabilities, including affiliates	(264		)	(9,257		)
Other liabilities	(6,609		)	519
Net loss	$	(507,786	)	$	(67,592	)
Add (deduct):
Depreciation and amortization	$	70,892		$	71,902
Interest expense	43,445			38,181
Revenue deferral adjustment	(416		)	3,016
Unit-based compensation	219			1,375
Income tax expense	1			4
Gain on sale of assets, net	(753		)	(5		)
Major litigation costs, net of recoveries	2,222			311
Equity in losses of joint venture investments	12,351			13,060
Severance expense	331			2,955
Retention bonus funded by Holdings	—			91
Transaction-related costs	2,702			3,752
Impairment of assets	430,313			1,769
Gain on insurance proceeds	—			(1,508		)
Expenses related to shut-down of Conroe processing plant and conversion of Gregory processing plant	—			1,568
Other, net	1,579			301
Adjusted EBITDA	$	55,100		$	69,180
Cash paid for interest	(38,265		)	(35,142		)
Income tax expense	(1		)	(4		)
Maintenance capital expenditures	(2,885		)	(4,789		)
Distributable cash flow	$	13,949		$	29,245

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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, 2018			June 30,  2018			September 30, 2018			December 31, 2018
Net cash provided by (used in) operating activities	$	(915	)	$	3,708		$	546		$	12,313
Add (deduct):
Depreciation and amortization	(17,856		)	(17,906		)	(17,787		)	(17,343		)
Unit-based compensation	(65		)	(105		)	(40		)	(9		)
Amortization of deferred financing costs, original issuance discount and PIK interest	(1,275		)	(1,495		)	(1,373		)	(1,399		)
Gain on sale of assets, net	—			553			84			116
Unrealized gain (loss) on financial instruments	5			(4		)	12			(4		)
Equity in losses of joint venture investments	(3,136		)	(3,152		)	(3,161		)	(2,902		)
Impairment of assets	—			—			—			(430,313		)
Other, net	63			63			63			63
Changes in operating assets and liabilities:
Trade accounts receivable, including affiliates (1)	(8,229		)	684			9,676			(9,294		)
Prepaid expenses and other current assets	7,225			(102		)	49			1,961
Other non-current assets	65			(600		)	(101		)	404
Accounts payable and accrued liabilities, including affiliates	11,274			(922		)	(2,665		)	(7,951		)
Other liabilities	(5,386		)	722			(524		)	(1,421		)
Net loss (1)	$	(18,230	)	$	(18,556	)	$	(15,221	)	$	(455,779	)
Add (deduct):
Depreciation and amortization	$	17,856		$	17,906		$	17,787		$	17,343
Interest expense	10,010			11,095			11,158			11,182
Income tax expense	—			—			—			1
Gain on sale of assets, net	—			(553		)	(84		)	(116		)
Revenue deferral adjustment	(104		)	(104		)	(104		)	(104		)
Unit-based compensation	65			105			40			9
Major litigation costs, net of recoveries	325			834			473			590
Transaction-related costs	620			197			123			1,762
Equity in losses of joint venture investments	3,136			3,152			3,161			2,902
Severance expense	—			—			331			—
Impairment of assets	—			—			—			430,313
Other, net	5			181			535			858
Adjusted EBITDA (1)	$	13,683		$	14,257		$	18,199		$	8,961

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	Three Months Ended
	March 31,			June 30,			September 30,			December 31,
	2018			2018			2018			2018
Revenues, as previously reported	$	156,630		$	137,420		$	154,804		$	171,707
Effect of error (1)	(1,393		)	(648		)	(387		)	—
Revenues, as corrected	155,237			136,772			154,417			171,707
Net loss, as previously reported	(16,837		)	(17,908		)	(14,834		)	(455,779		)
Effect of error (1)	(1,393		)	(648		)	(387		)	—
Net loss, as corrected	(18,230		)	(18,556		)	(15,221		)	(455,779		)
Trade accounts receivable, including affiliates, as previously reported	(6,836		)	1,332			10,063			(9,294		)
Effect of error (1)	(1,393		)	(648		)	(387		)	—
Trade accounts receivable, including affiliates, as corrected	(8,229		)	684			9,676			(9,294		)
Adjusted EBITDA, as previously reported	15,076			14,905			18,586			8,961
Effect of error (1)	(1,393		)	(648		)	(387		)	—
Adjusted EBITDA, as corrected	13,683			14,257			18,199			8,961
Basic and diluted net loss per common unit, as originally reported	(0.21		)	(0.22		)	(0.18		)	(3.75		)
Effect of error (1)	(0.02		)	(0.01		)	(0.01		)	—
Basic and diluted net loss per common unit, as corrected	(0.23		)	(0.23		)	(0.19		)	(3.75		)
Basic and diluted net loss per subordinated unit, as originally reported	(0.21		)	(0.22		)	(0.18		)	(3.75		)
Effect of error (1)	(0.02		)	(0.01		)	(0.01		)	—
Basic and diluted net loss per subordinated unit, as corrected	(0.23		)	(0.23		)	(0.19		)	(3.75		)

(1) Subsequent to the issuance of the September 30, 2018 interim financial statements, the Partnership identified an error in the accounts receivable - affiliates financial statement line item related to the reconciliation of residue imbalances between the Partnership and Holdings within the March 31, 2018, June 30, 2018 and September 30, 2018 consolidated statements of operations. As a result, the Partnership corrected previously reported amounts for each of these periods as indicated in the table above. The correction resulted in a decrease to Revenue and Adjusted EBITDA for each respective period. The Partnership has assessed these errors and determined they are immaterial. In future interim filings, these prior period amounts will be corrected when presented comparatively.

Key Factor Affecting Operating Results and Financial Condition

• Termination of AMIDTransactions. In July 2018, we terminated the Merger Agreement and Contribution Agreement, since the transactions contemplated by the Merger Agreement and Contribution Agreement were not completed on or prior to June 15, 2018 due to AMID’s Funding Failure (as defined in the Contribution Agreement). Pursuant to the terms of the Contribution Agreement, AMID was obligated to pay Holdings a fee of $17 million as a result of such termination. On August 1, 2018, AMID paid the $17 million termination fee to Holdings, of which $4.2 million was contributed to the Partnership and was used to reimburse the Partnership’s transaction costs.

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Results of Operations

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

	Year Ended December 31,
	2018			2017
Revenues:
Revenues	$	401,610		$	470,237
Revenues - affiliates	216,523			195,712
Total revenues	618,133			665,949
Expenses:
Cost of natural gas and liquids sold	489,932			524,675
Operations and maintenance	57,932			59,217
Depreciation and amortization	70,892			71,902
General and administrative	21,806			26,246
Impairment of assets	430,313			1,769
Gain on sale of assets, net	(753		)	(5		)
Total expenses	1,070,122			683,804
Loss from operations	(451,989		)	(17,855		)
Other income (expense):
Equity in losses of joint venture investments	(12,351		)	(13,060		)
Interest expense	(43,445		)	(38,181		)
Gain on insurance proceeds	—			1,508
Total other expense	(55,796		)	(49,733		)
Loss before income tax expense	(507,785		)	(67,588		)
Income tax expense	(1		)	(4		)
Net loss	$	(507,786	)	$	(67,592	)
Other financial data:
Adjusted EBITDA	$	55,100		$	69,180
Maintenance capital expenditures	$	2,885		$	4,789
Growth capital expenditures	$	9,249		$	18,001
Operating data:
Average volume of processed gas (MMcf/d)	245			250
Average volume of NGLs produced (Bbls/d)	30,131			30,824
Average daily throughput Mississippi/Alabama (MMcf/d)	166			166
Realized prices on natural gas volumes ($/Mcf)	$	3.31		$	3.17
Realized prices on NGL volumes ($/gal)	0.57			0.52

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2018 Compared with 2017

Volume and overview. Processed gas volumes decreased 5 MMcf/d, or 2%, to 245 MMcf/d during the year ended December 31, 2018, compared to 250 MMcf/d during the year ended December 31, 2017. This decrease in processed gas volumes is due primarily to record cold temperatures in January 2018 and lower volumes from producers, partially offset by the temporary shut-down of our processing plants as a result of Hurricane Harvey during the year ended December 31, 2017.

NGLs produced at our processing plants for the year ended December 31, 2018 averaged 30,131 Bbls/d, a decrease of 2%, or 693 Bbls/d, compared to 30,824 Bbls/d for the year ended December 31, 2017. The decrease in NGLs produced is due primarily to a decline in processed gas volumes, partially offset by higher ethane recoveries at our processing plants.

Revenue. Our total revenues for 2018 decreased $47.8 million, or 7%, to $618.1 million compared to $665.9 million in 2017. This decrease was due primarily to lower processed gas volumes compared to the same period in 2017. In addition, the decrease is due to the new revenue recognition standard under ASC 606.

Cost of natural gas and NGLs sold. Our cost of natural gas and NGLs sold for the year ended December 31, 2018 was $489.9 million, compared to $524.7 million for the year ended December 31, 2017. This decrease of $34.8 million, or 7%, was due primarily to lower processed gas volumes compared to the same period in 2017. In addition, the decrease is due to the new revenue recognition standard under ASC 606.

Operations and maintenance expenses. Operations and maintenance expenses for the year ended December 31, 2018 were $57.9 million, compared to $59.2 million for the year ended December 31, 2017 for a decrease of $1.3 million, or 2%. This decrease was due primarily to improved operating efficiencies at our facilities and lower variable expenses due to lower volumes.

General and administrative expenses. General and administrative expenses for the year ended December 31, 2018 were $21.8 million, compared to $26.2 million for the year ended December 31, 2017. This decrease of $4.4 million, or 17%, is due primarily to $4.1 million of lower employee related expenses during the year ended December 31, 2018.

Depreciation and amortization expense. Depreciation and amortization expense for the year ended December 31, 2018 was $70.9 million, compared to $71.9 million for the year ended December 31, 2017.

Impairment of assets. Impairment of assets for the year ended December 31, 2018 was $430.3 million, compared to $1.8 million for the year ended December 31, 2017. The asset impairment charge relates to our South Texas and Mississippi asset groups.

Equity in losses of joint venture investments.  Our share of losses incurred by our joint venture investments was $12.4 million for the year ended December 31, 2018 and $13.1 million for the year ended December 31, 2017. 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.

Interest expense. For the year ended December 31, 2018, interest expense was $43.4 million, compared to $38.2 million for the year ended December 31, 2017. This increase of $5.2 million, or 14%, was due primarily to higher interest rates on borrowings and PIK interest paid on the senior unsecured notes.

Liquidity and Capital Resources

Sources of Liquidity

Historically, our primary sources of liquidity has been 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. Our ability to issue additional indebtedness or access the capital markets may be substantially limited or nonexistent during our Chapter 11 proceedings and will require court approval. Accordingly, our liquidity will depend mainly on cash generated from operating activities and available funds under our DIP Financing. Factors that could impact our liquidity, capital resources and capital commitments include the following:

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• the outcome of potential strategic alternatives to maximize value for the benefit of our stakeholders as part of the Chapter 11 process, which may include a sale of certain or substantially all of our assets under Section 363 of the Bankruptcy Code or a plan of reorganization to equitize certain indebtedness;

• significant costs associated with the bankruptcy process, including our ability to limit these costs by obtaining confirmation of a successful plan of reorganization in timely manner;

• decisions from the Bankruptcy Court related to requirements to pay interest on certain debt instruments during the bankruptcy process;

• decisions from the Bankruptcy Court related to the rejection of certain executory contracts, including certain sales, firm transportation and gathering contracts;

• our ability to maintain compliance with debt covenants;

• our ability to fund, finance or repay indebtedness, including our ability to restructure our indebtedness during the Chapter 11 Cases;

• limitations on our ability to incur certain types of indebtedness in accordance with our debt agreements;

• requirements to provide certain vendors and other parties with letters of credit or cash deposits as a result of our credit quality, which reduce the amount of available borrowings under our DIP Financing;

• volatility in commodity prices or interest rates;

• industry and economic conditions;

• conditions in the financial markets;

• prices and demand for our services;

• potential acquisitions and/or dispositions of assets;

• the integration of acquisition assets;

• our ability to manage effectively operating, general and administrative expenses and capital expenditure programs; and

• the potential outcome of litigation.

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 experience declining volumes over a sustained period and/or unfavorable commodity prices.

Recent events affecting liquidity

Our liquidity and ability to maintain compliance with debt covenants have been negatively impacted by our levels of indebtedness. Despite our significant efforts to improve our financial condition, we have continued to face increasing liquidity concerns. Due to liquidity constraints and restrictions and limitations on our ability to pay interest in cash, common units or additional indebtedness, we did not make our interest payment of $7.4 million that was due on March 29, 2019.

On April 1, 2019, the Partnership and the Filing Subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. The Debtors have filed first day motions, which were designed primarily to minimize the impact of the Chapter 11 proceedings on our operations, customers and employees. Our capital budget for 2019 is limited in order to preserve

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our liquidity during the pendency of the bankruptcy process. We will continue to operate our businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. We expect to incur significant costs associated with the bankruptcy process, including legal, financial and restructuring advisors to the Partnership and certain of our creditors. Our ability to obtain confirmation of a successful plan of reorganization in timely manner is critical to ensuring our liquidity is sufficient during the bankruptcy process.

For the duration of the of the Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to significant risks and uncertainties associated with Chapter 11 proceedings. As a result of these significant risks and uncertainties, our assets, liabilities, unitholders’ equity (deficit), officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in these financial statements may not accurately reflect our operations, properties and capital plans following the Chapter 11 proceedings. See further discussion of the Chapter 11 proceedings in Note 14 to our consolidated financial statements.

The following table presents information relating to our liquidity and outstanding debt as of December 31, 2018 and February 28, 2019:

Our outstanding debt and related information at December 31, 2018 and February 28, 2019 is as follows (in thousands):

	As of
	February 28,			December 31,
	2019			2018
Revolving credit facility due 2019	$	81,124		$	81,124
Term loans due 2021	429,141			429,141
Senior unsecured notes payable due 2019	16,867			16,867
Original issuance discount on term loans due 2021	(762		)	(814		)
Total long-term debt (including current portion)	526,370			526,318
Current portion of long-term debt	(521,700		)	(521,123		)
Debt issuance costs	(4,670		)	(5,195		)
Total long-term debt	$	—		$	—

The filing of the Chapter 11 Cases described above constituted an event of default that accelerated our obligations under the following debt instruments:

• the Third A&R Revolving Credit Agreement;

• the Term Loan Agreement (as defined in Note 6 to our consolidated financial statements); and

• the Investment Notes.

These debt instruments provide that as a result of the commencement of the Chapter 11 Cases, the principal and interest due thereunder shall be immediately due and payable. Any efforts to enforce such payment obligations under the debt instruments are automatically stayed as a result of the commencement of the Chapter 11 Cases, and the creditors’ rights of enforcement in respect of the debt instruments are subject to the applicable provisions of the Bankruptcy Code.

On April 1, 2019, we filed a motion seeking entry of an order authorizing the Debtors to enter into the DIP Financing to, among other things, provide additional liquidity to fund our operations during the Chapter 11 process.

Pursuant to a Commitment Letter dated as of March 31, 2019 and the DIP Credit Agreement and the DIP Facility, to be entered into by the Loan Parties, the DIP Lenders, the DIP L/C Issuers, and the DIP Agent, the DIP Lenders have agreed to provide to the Loan Parties the DIP Financing in an aggregate principal amount of $255 million, consisting of (i) the DIP New Money Loan and (ii) the DIP LC Loan (collectively, the DIP Term Loans) to cash collateralize the DIP L/C Facility, and (iii) a senior secured priming superpriority term loan in the aggregate principal amount of $127.5 million, which will be subject and subordinate to the DIP New Money Facility and the DIP L/C Facility, to refinance dollar-for-dollar term loans outstanding under the DIP Loans. The DIP Loans are subject to approval by the Bankruptcy Court. The proceeds of the DIP Loans will be used for purposes permitted by the Bankruptcy Court and the DIP Credit Agreement, including (i) working capital and other general corporate purposes of the Loan Parties, including the refinancing of certain term loans and letters of credit, (ii) to pay transaction costs, professional fees, and other obligations and expenses incurred in connection with the DIP Facilities, the

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Chapter 11 Cases, and the transactions contemplated thereunder, and (iii) to make adequate protection payments to Southcross’s creditors under the Senior Credit Facilities to the extent set forth in any order entered by the Bankruptcy Court.

The DIP Facilities will mature on the earliest of (i) the date that is six months after the Petition Date (subject to one three month extension with the consent of the DIP Lenders constituting the required lenders under the DIP Facility), (ii) the effective date of a chapter 11 plan, (iii) the date on which all or substantially all of the assets of the Loan Parties are sold in a sale under a chapter 11 plan or pursuant to Section 363 of the Bankruptcy Code, and (iv) the date the DIP Facilities are accelerated following an event of default thereunder.  Subject to certain exceptions, the DIP Facility will be secured by a senior perfected security interest in substantially all of the assets of the Loan Parties, including the collateral securing the Senior Credit Facilities and any other previously unencumbered assets.

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.

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

	Year Ended December 31,
	2018		2017
Maintenance capital	$	2,885	$	4,789
Growth capital	9,249		18,001
Total capital expenditures	$	12,134	$	22,790

Our growth capital expenditures during the year ended December 31, 2018 primarily related to projects to connect new production of Y-grade supply to our assets, and management’s election to restart the Bonnie View fractionation facility (“Bonnie View”) in third quarter of 2018. Our growth capital expenditures during the year ended December 31, 2017, primarily relate to the installation of a new gas gathering pipeline in Mississippi which is used to gather incremental wellhead supply to sell to our end use markets in the area.

Cash Flows

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

	Year Ended December 31,
	2018			2017
Net cash provided by operating activities	$	15,652		$	26,182
Net cash used in investing activities	(9,776		)	(8,174		)
Net cash provided by (used in) financing activities	613			(34,016		)

2018 Compared with 2017

Operating Activities— Net cash provided by operating activities was $15.7 million for the year ended December 31, 2018, compared to $26.2 million for the year ended December 31, 2017. The decrease in cash provided by operating activities of $10.5 million was due primarily to a reduction in volumes, unfavorable pricing in the fourth quarter of 2018 and the timing of payments from working capital during the year ended December 31, 2018 compared to the year ended December 31, 2017.

Investing Activities—Net cash used in investing activities was $9.8 million for the year ended December 31, 2018, compared to $8.2 million for the year ended December 31, 2017. The increase of $1.6 million used in investing activities during the year ended December 31, 2018 was due primarily to $2.0 million of insurance proceeds from property damage claims, net of expenditures, $3.4 million of proceeds from the sale of assets and $9.9 million received from aid in construction payments during the year ended December 31, 2017, offset by lower capital expenditures of $11.1 million as compared to $22.8 million during the year ended December 31, 2017.

Financing Activities—Net cash provided by financing activities for the year ended December 31, 2018 was $0.6 million, compared to net cash used in financing activities of $34.0 million for the year ended December 31, 2017. The decrease of cash

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used in financing activities of $34.6 million was due primarily to the $15.0 million of borrowings contributed by the Sponsors in exchange for the Investment Notes, the $4.2 million contribution by Holdings to reimburse the Partnership for transaction costs during the year ended December 31, 2018, lower paydowns of $15.7 million on our Term Loan and Credit Facility, and lower financing costs of $0.3 million during the year ended December 31, 2018.

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

Upon adoption of Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”), when it is determined that a contract exists, our performance obligation has been met and our transaction price is 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, gathering, processing, treating, compression and other revenue is recognized in the period when the service is provided and represents our fee-based service revenue that is based upon the pricing terms of an executed contract. 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 presented separately 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 control is evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk.

Our gathering and processing agreements provide for quarterly and annual minimum volume commitments ("MVC"). Under these MVCs, our producers agree to sell us, 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.

We recognize customer obligations under their MVCs as revenue when our performance obligation has been met or when it is unlikely the producer will be able to meet its MVC commitment.

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

72

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 fourth quarter of 2018, Holdings and Holdings Borrower completed the sale of the Robstown facility and related pipelines to EPIC and EPIC Y-Grade Holdings LP. In connection with the completion of this sale, we identified certain Holdings and Holdings Borrower asset groups where events or circumstances indicated their carrying value may not be recovered. As a result of this analysis, we were required to obtain the fair-value of each of the South Texas, Mississippi and Alabama asset groups to determine the impairment loss to be recorded in the Holdings and Holdings Borrower consolidated financial statements. Also, during the fourth quarter of 2018, we recorded asset impairment charges of $430.3 million million to our South Texas and Mississippi asset groups. Of the $430.3 million impairment charge to our property, plant and equipment, $379.5 million related to our South Texas asset group and $50.8 million million to our Mississippi asset group.

During the year ended December 31, 2017, we recorded an impairment loss of $1.8 million related to the write-down of assets held for sale at the Gregory processing facility and canceled AFEs.

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	74
Consolidated Balance Sheets as of December 31, 2018 and 2017	76
Consolidated Statements of Operations for the Years Ended December 31, 2018 and 2017	77
Consolidated Statements of Cash Flows for the Years Ended December 31, 2018 and 2017	78
Consolidated Statements of Changes in Partners' Capital (Deficit) for the Years Ended December 31, 2018 and 2017	79
Notes to Consolidated Financial Statements	80

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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, 2018 and 2017, the related consolidated statements of operations, changes in partners’ capital (deficit) and cash flows, for each of the two years in the period ended December 31, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

Going Concern

The accompanying financial statements have been prepared assuming that the Partnership will continue as a going concern. As discussed in Note 2 to the financial statements, the Partnership is in default of certain covenants contained in its debt agreements and on April 1, 2019, the Partnership filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code that raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also discussed in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Bankruptcy Proceedings

As discussed in Notes 1 and 14 to the financial statements, on April 1, 2019, the Partnership filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. The accompanying financial statements do not purport to reflect or provide for the consequences of the bankruptcy proceedings. In particular, such financial statements do not purport to show (1) as to assets, their realizable value on a liquidation basis or their availability to satisfy liabilities; (2) as to prepetition liabilities, the settlement amounts for allowed claims, or the status and priority thereof; (3) as to shareholder accounts, the effect of any changes that may be made in the capitalization of the Partnership; or (4) as to operations, the effect of any changes that may be made in its business.

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.

/s/ Deloitte & Touche LLP

Dallas, Texas  

April 1, 2019  

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

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SOUTHCROSS ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands, except for unit data)

	December 31, 2018			December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	11,707		$	5,218
Trade accounts receivable	53,941			33,920
Accounts receivable - affiliates	5,980			33,163
Prepaid expenses	3,521			2,592
Other current assets	8,212			497
Total current assets	83,361			75,390
Property, plant and equipment, net	427,021			914,547
Investments in joint ventures	96,980			111,747
Other assets	3,090			2,519
Total assets	$	610,452		$	1,104,203
LIABILITIES AND PARTNERS' CAPITAL (DEFICIT)
Current liabilities:
Accounts payable and accrued liabilities	$	60,825		$	57,782
Accounts payable - affiliates	288			378
Current portion of long-term debt	521,123			4,256
Other current liabilities	15,309			12,976
Total current liabilities	597,545			75,392
Long-term debt	—			514,266
Other non-current liabilities	16,715			14,979
Total liabilities	614,260			604,637
Commitments and contingencies (Note 7)
Partners' capital (deficit):
Common units (48,686,215 and 48,614,187 units outstanding as of December 31, 2018 and 2017, respectively)	—			215,146
Class B Convertible units (19,652,831 and 18,335,181 units issued and outstanding as of December 31, 2018 and 2017, respectively)	9,393			266,725
Subordinated units (12,213,713 units issued and outstanding as of December 31, 2018 and 2017, respectively)	—			8,302
General partner interest	(13,201		)	9,393
Total partners' capital (deficit)	(3,808		)	499,566
Total liabilities and partners' capital (deficit)	$	610,452		$	1,104,203

See accompanying notes to these consolidated financial statements.

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SOUTHCROSS ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except for per unit data)

	Year Ended December 31,
	2018			2017
Revenues:
Revenues	$	401,610		$	470,237
Revenues - affiliates	216,523			195,712
Total revenues (Note 11)	618,133			665,949
Expenses:
Cost of natural gas and liquids sold	489,932			524,675
Operations and maintenance	57,932			59,217
Depreciation and amortization	70,892			71,902
General and administrative	21,806			26,246
Impairment of assets	430,313			1,769
Gain on sale of assets, net	(753		)	(5		)
Total expenses	1,070,122			683,804
Loss from operations	(451,989		)	(17,855		)
Other income (expense):
Equity in losses of joint venture investments	(12,351		)	(13,060		)
Interest expense	(43,445		)	(38,181		)
Gain on insurance proceeds	—			1,508
Total other expense	(55,796		)	(49,733		)
Loss before income tax expense	(507,785		)	(67,588		)
Income tax expense	(1		)	(4		)
Net loss	(507,786		)	(67,592		)
General partner unit in-kind distribution	(37		)	(65		)
Net loss attributable to partners	$	(507,823	)	$	(67,657	)
Earnings per unit:
Net loss allocated to limited partner common units	$	(213,943	)	$	(40,980	)
Weighted average number of limited partner common units outstanding	48,661			48,562
Basic and diluted loss per common unit	$	(4.40	)	$	(0.84	)
Net loss allocated to limited partner subordinated units	$	(7,948	)	$	(10,304	)
Weighted average number of limited partner subordinated units outstanding	12,214			12,214
Basic and diluted loss per subordinated unit	$	(0.65	)	$	(0.84	)

See accompanying notes to these consolidated financial statements.

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SOUTHCROSS ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2018			2017
Cash flows from operating activities:
Net loss	$	(507,786	)	$	(67,592	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization	70,892			71,902
Unit-based compensation	219			1,375
Amortization of deferred financing costs, original issuance discount and PIK interest	5,542			3,569
Gain on sale of assets, net	(753		)	(5		)
Unrealized loss (gain) on financial instruments	(9		)	2
Equity in losses of joint venture investments	12,351			13,060
Impairment of assets	430,313			1,769
Gain on insurance proceeds	—			(1,508		)
Other, net	(252		)	(474		)
Changes in operating assets and liabilities:
Trade accounts receivable, including affiliates	7,163			(5,425		)
Prepaid expenses and other current assets	(9,133		)	829
Other non-current assets	232			(58		)
Accounts payable and accrued liabilities, including affiliates	264			9,257
Other liabilities	6,609			(519		)
Net cash provided by operating activities	15,652			26,182
Cash flows from investing activities:
Capital expenditures	(11,100		)	(22,790		)
Aid in construction receipts	1,304			9,918
Insurance proceeds from property damage claims, net of expenditures	—			2,000
Net proceeds from sale of assets	500			3,409
Investment contributions to joint venture investments	(480		)	(711		)
Net cash used in investing activities	(9,776		)	(8,174		)
Cash flows from financing activities:
Borrowings under our senior unsecured note	15,000			—
Repayments under our credit facility	(13,431		)	(28,000		)
Repayments under our term loan agreement	(4,256		)	(5,353		)
Payments on capital lease obligations	(634		)	(487		)
Financing costs	(256		)	(44		)
Tax withholdings on unit-based compensation vested units	(11		)	(132		)
Contribution from parent	4,201			—
Net cash provided by (used in) financing activities	613			(34,016		)
Net increase (decrease) in cash and cash equivalents	6,489			(16,008		)
Cash and cash equivalents — Beginning of year	5,218			21,226
Cash and cash equivalents — End of year	$	11,707		$	5,218

See accompanying notes to these consolidated financial statements.

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SOUTHCROSS ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL (DEFICIT)

(In thousands)

	Partners' Capital (Deficit)
	Limited Partners									General Partner
	Common			Class B Convertible			Subordinated						Total
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 partners	—			—			—			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
Net loss	(213,943		)	(263,309		)	(7,948		)	(22,586		)	(507,786		)
Unit-based compensation on long-term incentive plan	219			—			—			—			219
Contribution from parent	—			4,201			—			—			4,201
Tax withholdings on unit-based compensation vested units	(11		)	—			—			—			(11		)
Contributions from general partner	—			—			—			3			3
General partner unit in-kind distribution	(22		)	(9		)	(6		)	37			—
Class B Convertible unit in-kind distribution	(1,389		)	1,785			(348		)	(48		)	—
BALANCE - December 31, 2018	$	—		$	9,393		$	—		$	(13,201	)	$	(3,808	)

See accompanying notes to these consolidated financial statements.

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SOUTHCROSS ENERGY PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 formed in April 2012. 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, one treating 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 and our General Partner (“General Partner”) (and therefore controls us), all of our subordinated and Class B convertible units and 54.4% of our common units. Our General Partner owns an approximate 2.0% interest in us and all of our incentive distribution rights. 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 Holdings' former term loan lenders own the remaining one-third of Holdings.

On April 1, 2019 (the "Petition Date"), the Partnership and certain of the Partnership's subsidiaries, including Southcross Energy Partners, L.P., our General Partner, Southcross Energy Finance Corp., Southcross Energy Operating, LLC, Southcross Energy GP LLC, Southcross Energy LP LLC, Southcross Gathering Ltd., Southcross CCNG Gathering Ltd., Southcross CCNG Transmission Ltd., Southcross Marketing Company Ltd., Southcross NGL Pipeline Ltd., Southcross Midstream Services, L.P., Southcross Mississippi Industrial Gas Sales, L.P., Southcross Mississippi Pipeline, L.P., Southcross Gulf Coast Transmission Ltd., Southcross Mississippi Gathering, L.P., Southcross Delta Pipeline LLC, Southcross Alabama Pipeline LLC, Southcross Nueces Pipelines LLC, Southcross Processing LLC, FL Rich Gas Services GP, LLC, FL Rich Gas Services, LP, FL Rich Gas Utility GP, LLC, FL Rich Gas Utility, LP, Southcross Transmission, LP, T2 EF Cogeneration Holdings, LLC, and T2 EF Cogeneration LLC (collectively the “Filing Subsidiaries” and, together with the Partnership and General Partner, the “Debtors”) filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). The Debtors’ have proposed to jointly administer their Chapter 11 cases under the caption In re Southcross Energy Partners, L.P., Case No. 19-10702 (the “Chapter 11 Cases”). We will continue to operate our businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The Debtors have filed with the Bankruptcy Court motions seeking a variety of first-day relief, which are designed primarily to minimize the impact of the Chapter 11 proceedings on our operations, customers and employees and includes a motion to obtain post-petition financing. We expect to continue our operations without interruption during the pendency of the Chapter 11 proceedings.

For the duration of the of the Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to significant risks and uncertainties associated with Chapter 11 proceedings. As a result of these significant risks and uncertainties, our assets, liabilities, unitholders’ equity (deficit), officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in these financial statements may not accurately reflect our operations, properties and capital plans following the Chapter 11 proceedings. See further discussion of the Chapter 11 proceedings in Note 14.

We were not able to reach an agreement with our creditors for a plan of reorganization prior to commencement of the Chapter 11 Cases. Therefore, the outcome of our Chapter 11 process is subject to a high degree of uncertainty and is dependent upon factors outside of our control, including actions of the Court and our creditors. The significant risks and uncertainties related to our liquidity and Chapter 11 proceedings described above raise substantial doubt about our ability to continue as a going concern. These consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. The accompanying consolidated financial statements do not include any adjustments to reflect the possible future effects of this uncertainty on the recoverability or classification of recorded asset amounts or the amounts or classification of liabilities. See Notes 2 and 14.

Delisting of Common Units from NYSE

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On February 27, 2019, the New York Stock Exchange (“NYSE”) notified the Partnership that the staff of NYSE Regulation, Inc. (the “NYSE Regulation”) had determined to commence proceedings to delist our common units. The NYSE Regulation reached its decision to delist our common units pursuant to Rule 802.01C of the NYSE’s Listed Company Manual, as the Partnership’s unit price had fallen below the NYSE’s continued listing standard with average closing price of less than $1.00 over a consecutive 30 trading-day period and failed to cure this non-compliance within the required timeframe. The NYSE suspended trading after the market close on the NYSE on February 27, 2019.

Effective February 28, 2019, our common units commenced trading on the OTCQX Marketplace under the ticker symbol "SXEE". On March 20, 2019, the NYSE filed with the SEC a notification of removal from listing and registration on Form 25 to delist our common units and terminate the registration of our common units under Section 12(b) of the Securities Exchange Act of 1934. The delisting became effective on April 1, 2019.

Holdings' Sale of Robstown Facility

On October 4, 2018, EPIC Midstream Holdings, LP (“EPIC”) and EPIC Y-Grade Holdings, LP, a subsidiary of EPIC,

entered into a definitive equity purchase agreement (the "Robstown Purchase Agreement") with Holdings and Holdings Borrower to acquire Holdings' Robstown fractionation facility ("Robstown") and related pipelines that enables Robstown to receive natural gas liquids from various supply sources and several short pipelines that allow the delivery of fractionated products to Corpus Christi-area markets. Under the terms of the agreement, EPIC assumed all of the NGL purchase and sale agreements associated with Robstown, including certain natural gas liquids sales and transportation agreements with the Partnership. The sale was completed in November 2018.

Termination of AMID Transactions

On July 29, 2018, we terminated the Agreement and Plan of Merger, dated October 31, 2017, by and among us, our General Partner, American Midstream Partners, LP, a Delaware limited partnership (“AMID”), American Midstream GP, LLC, a Delaware limited liability company and the general partner of AMID (“AMID GP”), and Cherokee Merger Sub LLC, a Delaware limited liability company and wholly owned subsidiary of AMID (“Merger Sub”) as amended by that certain Amendment No. 1 to Merger Agreement, dated as of June 1, 2018, by and among us, our General Partner, AMID, AMID GP and Merger Sub (as amended, the “Merger Agreement”), since the transactions contemplated by the Merger Agreement was not completed on or prior to June 15, 2018. As previously disclosed, under the Merger Agreement, we were to merge with and into Merger Sub, with the Partnership surviving the merger as a wholly owned subsidiary of AMID.

Simultaneously, on July 29, 2018, Holdings terminated the Contribution Agreement, dated October 31, 2017, by and among Holdings, AMID and AMID GP, as amended by that certain Amendment No. 1 to Contribution Agreement, dated as of June 1, 2018, by and among Holdings, AMID and AMID GP (as amended, the “Contribution Agreement”), since the transactions contemplated by the Contribution Agreement were not completed on or prior to June 15, 2018 due to AMID’s Funding Failure (as defined in the Contribution Agreement). Pursuant to the terms of the Contribution Agreement, AMID was obligated to pay Holdings a fee of $17 million as a result of such termination. On August 1, 2018, AMID paid the $17 million termination fee to Holdings, of which $4.2 million was contributed to the Partnership and was used to reimburse the Partnership's transaction costs.

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.

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.

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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

Upon adoption of ASC 606, we recognize revenue when it is determined that a contract exists, our performance obligation has been met and the transaction price is determinable. We recognize 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, gathering, processing, treating, compression and other revenue is recognized in the period when the service is provided and represents our fee-based service revenue that is based upon the pricing terms of an executed contract. 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 presented separately 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 control is evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk.

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

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

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

• Commodity-Sensitive.  In exchange for our processing services, we may remit to a customer a percentage of the proceeds from our sales, or a percentage of the physical volume, of residue natural gas and/or NGLs that result from our natural gas processing, or we may purchase NGLs from customers at set fixed NGL recoveries and retain the balance of the proceeds or physical commodity for our own account. These arrangements are generally combined with 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.

Our gathering and processing agreements provide for quarterly and annual minimum volume commitments ("MVC").Under these MVCs, our producers agree to sell us, 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

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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.

We recognize customer obligations under their MVCs as revenue when our performance obligation has been met or when it is remote the producer will be able to meet its MVC commitment.

Long-Lived Assets

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

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

Impairment of Long-Lived Assets

We evaluate our long-lived assets 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. We continually monitor our operations, the market, and business environment to identify indicators that could suggest an asset or asset group may not be recoverable. 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.

Following Holdings’ sale of Robstown during the fourth quarter of 2018, Holdings performed recoverability testing of its assets, including the consolidated assets of the Partnership. As a result of such testing, we received evidence that indicated we may not be able to recover the carrying values of our assets. We performed a separate recoverability test of our assets and concluded that the carrying amounts of our long-lived asset groups exceeded the expected future probability-weighted undiscounted cash inflows. We then determined the estimated fair-values of our South Texas, Mississippi, and Alabama asset groups. During the fourth quarter of 2018, we recorded asset impairment charges of $430.3 million to our South Texas and Mississippi asset groups. Of the $430.3 million impairment charge to our property, plant and equipment, $379.5 million related to our South Texas asset group and $50.8 million to our Mississippi asset group. See Note 5.

During the year ended December 31, 2017, we recorded an impairment loss of $1.8 million related to the write-down of assets held for sale at the Gregory processing facility and canceled AFEs.

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, 2018 and 2017, 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 no allowance for uncollectible accounts receivable at December 31, 2018 and 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 estimate on a reasonable basis any future AROs. No AROs were recorded for the years ended December 31, 2018 and 2017.

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, 2018 and 2017.

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, 2018 and 2017, 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 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, 2018 and 2017. 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, 2018 and 2017, 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, 2018, 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 two joint ventures in South Texas with a subsidiary of Targa Resources Corp. ("Targa") as our joint venture partner. These two joint ventures, T2 Eagle Ford Gathering Company LLC (“T2 Eagle Ford”) and T2 LaSalle Gathering Company LLC (“T2 LaSalle”), operate natural gas pipelines. Prior to December 31, 2018, we owned a third joint venture with Targa, T2 EF Cogeneration Holdings LLC (“T2 Cogen”), which operates an electric cogeneration facility. We indirectly own a 50% interest in T2 Eagle Ford and a 25% interest in T2 La Salle, and prior to December 31, 2018, we indirectly owned a 50% interest in T2 Cogen. We owned 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.

We previously had a third joint venture arrangement with T2 EF Cogeneration Holdings LLC (“T2 Cogen”) which operated a cogeneration facility next to our Lone Star plant that was accounted for as an equity method investment. On December 31, 2018, Targa and the Partnership as part of a settlement of previous disputes, agreed to terminate the T2 Cogen joint venture and distributed one cogeneration unit to Targa, while the Partnership acquired 100% interest in T2 Cogen. Therefore, as of the effective date of December 31, 2018, T2 Cogen was no longer accounted for as an equity method investment and was consolidated into the Partnership. In addition, under the terms of the settlement, T2 Eagle Ford and T2 LaSalle will be operated by Targa after the completion of a transition period. Our indirect ownership percentages will remain the same with respect to T2 Eagle Ford and T2 LaSalle, and therefore continue to be accounted for as equity method investments. 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 May 2014, the Financial Accounting Standards Board (“FASB”) issued ASC 606, which is a comprehensive new revenue recognition standard that superseded substantially all existing revenue recognition guidance under GAAP. The

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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. Since 2014, the FASB has issued a series of accounting pronouncements that update the identifying performance obligations and licensing implementation guidance. The Partnership implemented ASC 606 effective on January 1, 2018, applying ASC 606 to customer contracts which were not completed as of the effective date, using the modified retrospective method of adoption. As a result, we anticipate the timing of our revenue to remain the same with respect to the majority of our contracts.

Under the new standard, we identified certain natural gas purchase contracts that contained fees which were previously recognized as revenue for services provided to producers. Beginning on January 1, 2018, the fee revenue which previously was presented within revenue is now presented within the costs of natural gas and liquids sold line item within the consolidated statement of operations. We also have certain natural gas sales contracts with customers whereby the customers provide certain aid-in-construction capital expenditure payments to us to construct pipelines on our operating assets which we own and operate. We previously accounted for these arrangements as a reduction to property, plant and equipment. Under the new standard, we reclassified these payments as deferred revenue on our consolidated balance sheets at January 1, 2018, which resulted in a $2.7 million cumulative effect of accounting change being recorded to increase property, plant and equipment. The deferred revenue will be amortized over five years, the expected length of the contract.

New Accounting Pronouncements

In February 2016, the FASB issued a pronouncement 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) are to 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 are to 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. In January 2018, the FASB issued an updated accounting pronouncement which permits an entity to elect an optional transition method to not evaluate land easements that exist or expired before the entity’s adoption of the new leasing standard and that were not previously accounted for as leases. In July 2018, the FASB issued an updated accounting pronouncement which permits an entity to apply initially the new leasing standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance sheet of partners’ equity (deficit) in the period of adoption. We plan to utilize the practical expedient to not evaluate land easements using the modified retrospective method of adoption. We expect these leases to be classified as operating leases and do not expect a material balance in direct financing type leases. Capital leases, as disclosed in Note 7, will be classified as sales-type leases upon adoption. The lease pronouncement will become effective beginning in 2019.

2. LIQUIDITY CONSIDERATIONS AND ABILITY TO CONTINUE AS A GOING CONCERN

Our liquidity and ability to maintain compliance with debt covenants have been negatively impacted by our level of indebtedness. Our future cash flow may be materially adversely affected if the natural gas and NGL volumes connected to our system decline. See Note 1. 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 and our success in connecting volumes to our systems. Despite our significant efforts to improve our financial condition, we have continued to face increasing liquidity concerns.

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, (i) the total aggregate commitments under the Third A&R Revolving Credit Agreement were reduced from $200 million to $115 million and the sublimit for letters of credit was also reduced from $75 million to $50 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 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 were required to maintain minimum levels of Consolidated

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EBITDA (as defined in the Fifth Amendment) on a quarterly basis and were 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 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 and Term Loan 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”).

On July 29, 2018, we terminated the Agreement and Plan of Merger, dated October 31, 2017, by and among us, our General Partner, American Midstream Partners, LP, a Delaware limited partnership (“AMID”), American Midstream GP, LLC, a Delaware limited liability company and the general partner of AMID (“AMID GP”), and Cherokee Merger Sub LLC, a Delaware limited liability company and wholly owned subsidiary of AMID (“Merger Sub”) as amended by that certain Amendment No. 1 to Merger Agreement, dated as of June 1, 2018, by and among us, our General Partner, AMID, AMID GP and Merger Sub (as amended, the “Merger Agreement”), since the transactions contemplated by the Merger Agreement was not completed on or prior to June 15, 2018. As previously disclosed, under the Merger Agreement, we were to merge with and into Merger Sub, with the Partnership surviving the merger as a wholly owned subsidiary of AMID.

On August 10, 2018, we entered into the sixth amendment (the “Sixth Amendment”) to the Third A&R Revolving Credit Agreement which, among other things, reduced the Consolidated Interest Coverage Ratio from 1.50 to 1.00 to 1.25 to 1.00 for the period ending on June 30, 2018. See Note 6.

During management's ongoing assessment of the Partnership's financial forecast, the board of directors of Southcross Holdings GP, LLC (the “Holdings GP Board”) and the board of directors of our General Partner (the “Partnership GP Board”), together with our management, determined that in the then current corporate capital structure and absent continued access to equity cures from our Sponsors or a significant equity infusion from a third party, or absent additional amendments to its Third A&R Revolving Credit Agreement (which matures on August 4, 2019) or waivers of the March 31, 2019 requirement to comply with the Consolidated Total Leverage Ratio and minimum Adjusted EBITDA (both as defined in the Fifth Amendment) and Consolidated Interest Coverage Ratio (as defined in the Sixth Amendment), the Partnership was not expected to be able to comply with such financial covenants, which would have triggered an event of default under the Senior Credit Facilities.

In March 2019, in light of (a) the August 4, 2019 maturity of the Third A&R Revolving Credit Agreement, (b) the impending non-compliance with our Consolidated Total Leverage Ratio, minimum Adjusted EBITDA and Consolidated Senior Secured Leverage Ratio (each as defined in the Fifth Amendment - see Notes 2 and 6) at March 31, 2019 that would result in an event of default under the Senior Credit Facilities, (c) our non-compliance with our minimum Adjusted EBITDA and Consolidated Interest Coverage Ratio as of December 31, 2018 (see Note 6); and (d) the inclusion of a going concern uncertainty explanatory paragraph in the audit opinion on our consolidated financial statements, which constitutes an event of default under the Senior Credit Facilities, we elected not to make the approximately $7.4 million interest payment on our Term Loan that was due on March 29, 2019. While we have been in discussions with our creditors, those discussions did not produce an agreement that would enable us to address effectively, in a holistic manner, the impending issues adversely impacting our business, including (i) impending maturity of the Third A&R Revolving Credit Agreement, (ii) current and potential near-term breaches of certain financial covenants, and (iii) certain other potential defaults under our Senior Credit Facilities.

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Despite our efforts to improve our financial condition, we continued to face increasing liquidity concerns. As of March 20, 2019, our liquidity was $2.1 million. On April 1, 2019, the Partnership, General Partner and the Filing Subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code.

On April 1, 2019, we filed a motion seeking entry of an order authorizing the Debtors to enter into the Debtor-in-Possession financing (“DIP Financing”) to, among other things, provide additional liquidity to fund our operations during the Chapter 11 process.

Pursuant to a Commitment Letter dated as of March 31, 2019 and Form Credit Agreement attached thereto (the “DIP Credit Agreement” and, the facility thereunder, the “DIP Facility”), to be entered into by  Southcross, as borrower, its direct and indirect Debtor subsidiaries, as guarantors (the “Guarantors” and, together with Southcross, the “Loan Parties”), certain of our creditors under the Senior Credit Facilities, as lenders (the “DIP Lenders”) and letter of credit issuers (the “DIP L/C Issuers”), and Wilmington Trust, National Association, as administrative agent (the “DIP Agent”), the DIP Lenders have agreed to provide to the Loan Parties the DIP Financing in an aggregate principal amount of $255 million, consisting of (i) a senior secured priming superpriority term loan in the aggregate principal amount of $72.5 million (the “DIP New Money Loan”), (ii) a senior secured priming superpriority term loan in the aggregate principal amount of $55 million (the “DIP LC Loan” and, together with the DIP New Money Loans, the “DIP Term Loans”) to cash collateralize a letter of credit sub-facility for the issuance of letters of credit by certain issuing banks that will be party to the DIP Credit Agreement (the “DIP L/C Facility”), and (iii) a senior secured priming superpriority term loan in the aggregate principal amount of $127.5 million, which will be subject and subordinate to the DIP New Money Facility and the DIP L/C Facility, to refinance dollar-for-dollar term loans outstanding under the Term Loan Agreement owed to the DIP Lenders (the “DIP Roll-Up Loan” and, together with the DIP Term Loans, the “DIP Loans”).  The DIP Loans are subject to approval by the Bankruptcy Court. The proceeds of the DIP Loans will be used for purposes permitted by the Bankruptcy Court and the DIP Credit Agreement, including (i) working capital and other general corporate purposes of the Loan Parties, including the refinancing of certain term loans and letters of credit, (ii) to pay transaction costs, professional fees, and other obligations and expenses incurred in connection with the DIP Facilities, the Chapter 11 Cases, and the transactions contemplated thereunder, and (iii) to make adequate protection payments to Southcross’s creditors under the Senior Credit Facilities to the extent set forth in any order entered by the Bankruptcy Court.

The DIP Facilities will mature on the earliest of (i) the date that is six months after the Petition Date (subject to one three month extension with the consent of the DIP Lenders constituting the required lenders under the DIP Facility), (ii) the effective date of a chapter 11 plan, (iii) the date on which all or substantially all of the assets of the Loan Parties are sold in a sale under a chapter 11 plan or pursuant to Section 363 of the Bankruptcy Code, and (iv) the date the DIP Facilities are accelerated following an event of default thereunder.  Subject to certain exceptions, the DIP Facility will be secured by a senior perfected security interest in substantially all of the assets of the Loan Parties, including the collateral securing the Senior Credit Facilities and any other previously unencumbered assets.

We continue to engage in discussions with our creditors regarding the terms of a financial restructuring plan. In conjunction with this process, we will explore potential strategic alternatives to maximize value for the benefit of our stakeholders, which may include a sale of certain or substantially all of our assets under Section 363 of the Bankruptcy Code, a plan of reorganization to equitize certain indebtedness as an alternative to the sale process, or a combination thereof.

We were not able to reach an agreement with our creditors for a plan of reorganization prior to commencement of the Chapter 11 Cases. Therefore, the outcome of our Chapter 11 process is subject to a high degree of uncertainty and is dependent upon factors outside of our control, including actions of the Court and our creditors. The conditions and events described above including the impending maturity of the Third A&R Revolving Credit Agreement, current and potential near-term non-compliance with certain financial covenants, and Chapter 11 proceedings raise substantial doubt about our ability to continue as a going concern.

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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, 2018 and 2017 (in thousands, except unit and per unit data):

	Year Ended December 31,
	2018			2017
Net loss	$	(507,786	)	$	(67,592	)
General partner unit in-kind distribution	(37		)	(65		)
Net loss attributable to partners	$	(507,823	)	$	(67,657	)
General partner's interest(1)	$	(22,623	)	$	(1,417	)
Class B Convertible limited partner interest(1)	(263,309		)	(14,956		)
Limited partners' interest(1)
Common	$	(213,943	)	$	(40,980	)
Subordinated	(7,948		)	(10,304		)

_____________________________________________________________

(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.

	Year Ended December 31,
Common Units	2018			2017
Interest in net loss	$	(213,943	)	$	(40,980	)
Effect of dilutive units - numerator(1)	—			—
Dilutive interest in net loss	$	(213,943	)	$	(40,980	)
Weighted-average units - basic	48,661,470			48,562,193
Effect of dilutive units - denominator(1)	—			—
Weighted-average units - dilutive	48,661,470			48,562,193
Basic and diluted net loss per common unit	$	(4.40	)	$	(0.84	)

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	Year Ended December 31,
Subordinated Units	2018			2017
Interest in net loss	$	(7,948	)	$	(10,304	)
Effect of dilutive units - numerator(1)	—			—
Dilutive interest in net loss	$	(7,948	)	$	(10,304	)
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	$	(0.65	)	$	(0.84	)

____________________________________________________________________________

(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 214,182 and 43,811 and unvested awards granted under our LTIP for the years ended December 31, 2018 and 2017, respectively.

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 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.

The board of directors of our General Partner (the "Partnership GP Board") suspended paying a quarterly distribution with respect to the fourth quarter of 2015 and every quarter of 2016, 2017 and 2018 to conserve any excess cash for the operation of our business and due to restrictions imposed by our debt instruments.

Paid In-Kind Distributions

Class B Convertible Units. As of December 31, 2018, the Class B Convertible Units consisted of 19,652,831 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 the 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 to the consolidated financial statements..

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The following table represents the PIK distribution paid on the Class B Convertible Units for periods ended December 31, 2018 and 2017 (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)
2018
February 7, 2019	December 31, 2018	$	0.3257	343,950	$	76	7,019	$	2
November 12, 2018	September 30, 2018	0.3257		338,034	196		6,899	4
August 13, 2018	June 30, 2018	0.3257		332,220	515		6,780	11
May 3, 2018	March 31, 2018	0.3257		326,506	532		6,663	11
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

(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.

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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 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 had a non-recurring Level 3 fair-value measurement associated with the impairment of our fixed assets. See Note 5.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, 2018, the fair-value of our term loan was $387.0 million and the fair-value of the Investment Notes (defined in Note 6) was $15.2 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, 2018
40,000	2.575	%	December 31, 2018	June 30, 2019	11
40,000	3.000	%	December 31, 2016	January 1, 2019	—
60,000	3.000	%	June 30, 2017	June 30, 2019	—
175,000	4.000	%	June 30, 2018	June 30, 2019	—
					$	11

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, 2018 and 2017.

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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, 2018		December 31, 2017
Current interest rate derivative assets	$	11	$	1
Non-current interest rate derivative assets	—		1
Total interest rate derivatives	$	11	$	2

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

	Year Ended December 31,
	2018			2017
Unrealized loss (gain) on interest rate derivatives	$	(9	)	$	2
Realized gain on interest rate derivatives	—			(15		)

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,
		2018			2017
Pipelines	15-30	$	224,752		$	571,730
Gas processing, treating and other plants	15	169,899			520,765
Compressors	5-15	16,058			78,997
Rights of way and easements	15	13,968			49,897
Furniture, fixtures and equipment	5	2,577			9,746
Capital lease vehicles	3-5	2,944			2,114
Total property, plant and equipment		430,198			1,233,249
Accumulated depreciation and amortization		(17,726		)	(334,528		)
Total		412,472			898,721
Construction in progress		8,234			2,173
Land and other		6,315			13,653
Property, plant and equipment, net		$	427,021		$	914,547

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, 2018 and 2017, was $70.9 million and $71.9 million, respectively.

As part of Partnership-wide cost-saving initiatives, management elected to 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. 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.

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 was being sold to Holdings in accordance with our affiliate Y-grade sales agreement and was being fractionated at the Robstown fractionation facility. However, during the fourth quarter of 2018, Holdings and Holdings Borrower completed the sale of the Robstown facility and related pipelines to EPIC and EPIC Y-Grade Holdings, LP, a subsidiary of EPIC, that enables the Robstown facility to receive natural gas liquids from various supply sources and several short pipelines that allow the delivery of fractionated products to

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Corpus Christi-area markets. Under the terms of the Robstown Purchase Agreement, EPIC assumed all of the NGL purchase and sale agreements associated with Robstown, including those with the Partnership through December 31, 2019. Bonnie View will continue to serve as a backup option for EPIC to the extent Robstown is unable to fractionate our Y-grade product. Also, EPIC has the option to request that the Partnership restart Bonnie View for the benefit of EPIC through December 31, 2019. At this time, we have no plans to restart Bonnie View and we will continue to operate the facility as a truck unloading facility and pipeline Y-grade receipt point.

We received a settlement payment of $2.0 million from our insurance carriers in the first quarter of 2017 related to the fire at our Gregory facility in 2015, and recorded a $1.5 million gain related to insurance proceeds received in excess of expenditures incurred to repair the Gregory facility. 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.

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. We continually monitor our operations, the market, and business environment to identify indicators that could suggest an asset or asset group may not be recoverable. 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.

Following Holdings’ sale of Robstown during the fourth quarter of 2018, Holdings performed recoverability testing of its assets, including the consolidated assets of the Partnership. As a result of such testing, we received evidence that indicated we may not be able to recover the carrying values of our assets. We performed a separate recoverability test of our assets and concluded that the carrying amounts of our long-lived asset groups exceeded the expected future probability-weighted undiscounted cash inflows. We then determined the estimated fair-values of our South Texas, Mississippi, and Alabama asset groups. During the fourth quarter of 2018, as part of a non-recurring valuation of our long-lived assets, we determined that the fair value of our South Texas and Mississippi assets groups was a combined $501.7 million as of October 2018. Therefore, we recorded asset impairment charges of $430.3 million to our South Texas and Mississippi asset groups. Of the $430.3 million impairment charge to our property, plant and equipment, $379.5 million related to our South Texas asset group and $50.8 million million to our Mississippi asset group. This related impairment charge is a non-recurring Level 3 fair-value measurement.

During the year ended December 31, 2017, we recorded an impairment loss of $1.8 million related to the write-down of assets held for sale at the Gregory processing facility and canceled AFEs.

Intangible Assets

Intangible assets of $1.3 million and $1.3 million as of December 31, 2018 and 2017, 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.

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6. LONG-TERM DEBT

Our outstanding debt and related information at December 31, 2018 and 2017 is as follows (in thousands):

	As of December 31,
	2018			2017
Revolving credit facility due 2019	$	81,124		$	94,555
Term loans due 2021	429,141			433,396
Senior unsecured notes payable due 2019	16,867			—
Original issuance discount on term loans due 2021	(814		)	(1,134		)
Total long-term debt (including current portion)	526,318			526,817
Current portion of long-term debt	(521,123		)	(4,256		)
Debt issuance costs	(5,195		)	(8,295		)
Total long-term debt	$	—		$	514,266
Outstanding letters of credit	$	27,738		$	24,911
Remaining unused borrowings	$	6,138		$	15,534

	Year Ended December 31,
	2018			2017
Weighted average interest rate	7.16		%	6.09		%
Average outstanding borrowings	$	530,223		$	544,112
Maximum borrowings	$	532,952		$	561,305

On April 1, 2019, we filed a motion seeking entry of an order authorizing the Debtors to enter into the DIP Financing to, among other things, provide additional liquidity to fund our operations during the Chapter 11 process.

Pursuant to a Commitment Letter dated as of March 31, 2019 and the DIP Credit Agreement and the DIP Facility, to be entered into by the Loan Parties, the DIP Lenders, the DIP L/C Issuers, and the DIP Agent, the DIP Lenders have agreed to provide to the Loan Parties the DIP Financing in an aggregate principal amount of $255 million, consisting of (i) the DIP New Money Loan and (ii) the DIP LC Loan (collectively, the DIP Term Loans) to cash collateralize the DIP L/C Facility, and (iii) a senior secured priming superpriority term loan in the aggregate principal amount of $127.5 million, which will be subject and subordinate to the DIP New Money Facility and the DIP L/C Facility, to refinance dollar-for-dollar term loans outstanding under the DIP Loans. The DIP Loans are subject to approval by the Bankruptcy Court. The proceeds of the DIP Loans will be used for purposes permitted by the Bankruptcy Court and the DIP Credit Agreement, including (i) working capital and other general corporate purposes of the Loan Parties, including the refinancing of certain term loans and letters of credit, (ii) to pay transaction costs, professional fees, and other obligations and expenses incurred in connection with the DIP Facilities, the Chapter 11 Cases, and the transactions contemplated thereunder, and (iii) to make adequate protection payments to Southcross’s creditors under the Senior Credit Facilities to the extent set forth in any order entered by the Bankruptcy Court.

The DIP Facilities will mature on the earliest of (i) the date that is six months after the Petition Date (subject to one three month extension with the consent of the DIP Lenders constituting the required lenders under the DIP Facility), (ii) the effective date of a chapter 11 plan, (iii) the date on which all or substantially all of the assets of the Loan Parties are sold in a sale under a chapter 11 plan or pursuant to Section 363 of the Bankruptcy Code, and (iv) the date the DIP Facilities are accelerated following an event of default thereunder.  Subject to certain exceptions, the DIP Facility will be secured by a senior perfected security interest in substantially all of the assets of the Loan Parties, including the collateral securing the Senior Credit Facilities and any other previously unencumbered assets.

Senior Credit Facilities

Our long-term debt arrangements consist of (i) the Third A&R Revolving Credit Agreement and (ii) the Term Loan Agreement. Substantially all of our assets are pledged as collateral under the Senior Credit Facilities, with the security interest

of the facilities ranking pari passu.

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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 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 $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. Our Consolidated Interest Coverage Ratio was 1.21 to 1.00 as December 31, 2018, and thus out of compliance with our covenant;

(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. Our Consolidated EBITDA requirement was $57.5 million as of December 31, 2018, which we were out of compliance with as of 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

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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 10.40 to 1.00 as of December 31, 2018.

On August 10, 2018, we entered into the Sixth Amendment which, among other things, reduced the Consolidated Interest Coverage Ratio from 1.50 to 1.00 to 1.25 to 1.00 for the period ending on June 30, 2018. The Sixth Amendment, notwithstanding, 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 the Third A&R Revolving Credit Agreement (which matures on August 4, 2019) or waivers of the March 31, 2019 requirement to comply with the Consolidated Total Leverage Ratio and Consolidated EBITDA covenant (both as defined in the Fifth Amendment) and Consolidated Interest Coverage Ratio (as defined in the Sixth Amendment), the Partnership is not expected to comply with such financial covenants in the next twelve months, which will trigger an event of default under the Senior Credit Facilities. As a result, our expected inability to comply with our financial covenants, together with the expected maturity date of a significant portion of our borrowings within 12 months, we have classified all of our debt as current as of December 31, 2018.

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 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), such as the $1.064 million described in Note 5 during 2017, with the remainder due on the maturity date.

Senior Unsecured Note

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 contributed 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 (“PIK”) (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. The senior unsecured note payable includes $1.9 million of PIK interest as of December 31, 2018.

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,
	2018			2017
Deferred financing costs, January 1	$	8,295		$	11,474
Capitalization of deferred financing costs	255			84
Amortization of deferred financing costs	(3,355		)	(3,263		)
Deferred financing costs, December 31	$	5,195		$	8,295

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

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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.

For a discussion about the Chapter 11 Cases, see Note 14.

TPL. Effective as of December 31, 2018, we settled our arbitration with TPL SouthTex Processing Company, LP (“TPL”), an indirect subsidiary of Targa Resources Corp. (“Targa”), against FL Rich Gas Services, LP, an indirect subsidiary of the Partnership (“FL Rich”), related to the operation of T2 Cogen. T2 Cogen, owns a cogeneration facility in South Texas. FL Rich now owns 100% of T2 Cogen and is no longer a joint venture with TPL. TPL received one of the cogeneration units as part of the settlement agreement. See Note 12.

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 in 2016. No trial date has been set for the contractual liability claims in the case. On April 25, 2018, a judgment was entered against Southcross in the amount of approximately $7.7 million which have been appealed to the Texas Court of Appeals. We believe we have adequate insurance coverage to cover this matter and have recorded a $7.7 million liability and receivable from our insurance carrier. In April 2018 the plaintiffs filed two new lawsuits against Southcross CCNG Transmission Ltd. that allege the same or similar causes of actions for which we previously received a judgement in Duval County. The cases are styled as Ivy Gonzalez on behalf of M.R. Gonzalez and M.N. Gonzalez Minor Children vs. Southcross CCNG Transmission Ltd.; Gene Henneke as independent administrator of the estate of Dennis Henneke; Galbreath Contracting, Inc. and Severo Sepulveda, Jr. Cause no. DE-18-82 and Amy Gonzalez as co-personal representative of the estate of Jesus Gonzalez, Jr. under the Texas Survival Act and for and on behalf of wrongful death beneficiaries M.R. Gonzalez and M.N. Gonzalez Minor Children and Amy Gonzalez and Jesus Gonzalez, Sr. vs. Southcross CCNG Transmission Ltd.; Gene Henneke as independent administrator of the estate of Dennis Henneke; Galbreath Contracting, Inc. and Severo Sepulveda, Jr. Cause no. DE-18-83. We intend to defend vigorously these pending matters and believe we have adequate insurance coverage with respect to these matters.

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 2019 to 2022. We recorded amortization expense related to the capital leases of $0.6 million and $0.6 million for the years ended December 31, 2018 and 2017, respectively. Capital leases entered into during the years ended December 31, 2018 and 2017 were $1.6 million and $0.5 million. The capital lease obligation amounts included in the balance sheets were as follows (in thousands):

	December 31, 2018		December 31, 2017
Other current liabilities	$	646	$	410
Other non-current liabilities	1,054		410
Total	$	1,700	$	820

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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 2019 to 2025. Expenses associated with operating leases, recorded in operations and maintenance expenses and general and administrative expenses in our statements of operations, were $5.6 million and $5.8 million for the years ended December 31, 2018 and 2017, respectively. A rental reimbursement included in our lease agreement associated with the office space we leased in June 2015 of $1.8 million, net of amortization, has been recorded as a deferred liability in our consolidated balance sheets as of December 31, 2018. 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, 2018 were as follows (in thousands):

Years Ending December 31,	Capital Leases			Operating Leases
2019	$	646		$	2,912
2020	523			1,148
2021	414			922
2022	117			941
2023	—			953
Thereafter	—			1,956
Total future payments	1,700			$	8,832
Less: Imputed interest	$	(53	)
Future lease payments	$	1,647

8. TRANSACTIONS WITH RELATED PARTIES

Affiliated Directors

The Partnership GP Board 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 a group of Holdings' former term loan 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,
	2018		2017
EIG	144		165
Tailwater	152		170
Total fees and expenses paid for director services to affiliated entities	$	296	$	335

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,
	2018		2017
Reimbursements included in general and administrative expenses	$	7,558	$	11,176
Reimbursements included in operations and maintenance expenses	15,045		16,057
Total reimbursements to our General Partner and its affiliates	$	22,603	$	27,233

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Other Transactions with Affiliates

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. While the Partnership continues to have a G&P Agreement with Holdings, the NGL agreement was assigned to EPIC as of October 1, 2018 in connection with the sale by Holdings of Robstown. We had purchases of NGLs from Holdings of $3.9 million and $1.7 million for the years ended December 31, 2018 and 2017, respectively.

We recorded revenues from affiliates of $216.5 million and $195.7 million for the years ended December 31, 2018 and 2017, 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 $6.0 million and $33.2 million as of December 31, 2018 and 2017, respectively, and accounts payable due to affiliates of $0.3 million and $0.4 million as of December 31, 2018 and 2017, 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, 2018.

On July 29, 2018, Holdings terminated the Contribution Agreement since the transactions contemplated thereby were not completed on or prior to June 15, 2018 due to AMID’s Funding Failure (as defined in the Contribution Agreement). Pursuant to the terms of the Contribution Agreement, AMID was obligated to pay Holdings a $17 million termination fee as a result of such termination. On August 1, 2018, AMID paid the $17 million termination fee to Holdings, of which $4.2 million was contributed to the Partnership and was used to reimburse the Partnership’s transaction costs.

On October 4, 2018, EPIC and EPIC Y-Grade, a subsidiary of EPIC, entered into a definitive equity purchase agreement with Holdings and Holdings Borrower to acquire Robstown and related pipelines that enables the Robstown facility to receive natural gas liquids from various supply sources and several short pipelines that allow the delivery of fractionated products to Corpus Christi-area markets. Under the terms of the Robstown Purchase Agreement, EPIC assumed all of the NGL purchase and sale agreements associated with Robstown, including certain NGL sales and transportation agreements with the Partnership. The sale was completed in November 2018.

9. PARTNERS' CAPITAL

Ownership

Our units outstanding as of December 31, 2018 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, 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
Common unit issuances to Holdings related to equity cures	—	—	—	—	—
Units outstanding as of December 31, 2017	22,122,113	26,492,074	18,335,181	12,213,713	1,615,573
Vesting of LTIP units, net	59,289	—	—	—	—
In-kind distributions and issuances to general partner to maintain 2.0% ownership	—	—	1,317,650	—	28,101
Board of director grants	12,739	—	—	—	260
Units outstanding as of December 31, 2018	22,194,141	26,492,074	19,652,831	12,213,713	1,643,934

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Common units

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

Class B Convertible Units

As of December 31, 2018, the Class B Convertible Units consist of 19,652,831 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, 2018, 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 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. On May 3, 2018, we issued 326,506 Class B Convertible Units to Holdings and 6,663 general partner units to our General Partner related to the quarter ended March 31, 2018. On August 13, 2018, we issued 332,220 Class B Convertible Units to Holdings and 6,780 general partner units to our General Partner related to the quarter ended June 30, 2018. On November 12, 2018, we issued 338,034 Class B Convertible Units to Holdings and 6,899 general partner units to our General Partner related to the quarter ended September 30, 2018. On February 7, 2019, we issued 343,950 Class B Convertible Units to Holdings and 7,019 general partner units to our General Partner for the quarter ended December 31, 2018.

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 to the consolidated financial statements.

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

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Partner has made capital contributions in exchange for additional 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.

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

	Units		Weighted-Average Fair-Value at Grant Date
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
Forfeited units	(4,468	)	$	13.63
Units recaptured for tax withholdings (1)	(22,005	)	$	8.78
Vested Units (1)	(59,289	)	$	5.24
Unvested - December 31, 2018	12,334		$	7.94

(1) The weighted-average fair-value price on the date of vesting for our vested units was $1.41 and $2.63 for the years ended December 31, 2018 and 2017. The weighted-average fair-value price on the date of vesting for our units recaptured for tax withholdings was $1.46 and $2.68 for the years ended December 31, 2018 and 2017.

For the year ended December 31, 2017, we did not grant any equity awards under the LTIP. For the year ended December 31, 2018, we granted awards under the LTIP with a grant date fair-value of $0.1 million which immediately vested on that grant date. As of December 31, 2018 and 2017, we had total unamortized compensation expense of $0.1 million and $0.3 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, 2018 and 2017, we had 5,343,738 and 5,330,004 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,
	2018		2017
Unit-based compensation	$	219	$	1,375

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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 $16,500 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,
	2018		2017
Matching contributions expensed for employee savings plan	$	586	$	731

11. REVENUES

Upon adoption of ASC 606, when it is determined that a contract exists, our performance obligation has been met and our transaction price is 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, gathering, processing, treating, compression and other revenue is recognized in the period when the service is provided and represents our fee-based service revenue that is based upon the pricing terms of an executed contract. 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 presented separately 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 control is evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk.

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

• Fixed-Fee. We receive a fixed-fee per unit of natural gas volume that we gather at the wellhead, process, treat, compress and/or transport for our customers, or we receive a fixed-fee per unit of NGL volume that we transport to fractionation. 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-based 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-based price, plus or minus a fixed price differential. By entering into such back-to-back purchases and sales, we are able to mitigate our risk associated with changes in the general commodity price levels of natural gas and NGLs. We remain subject to variations in our fixed-spreads to the extent we are unable to precisely match volumes purchased and sold in a given time period or are unable to secure the supply or to produce or market the necessary volume of products at our anticipated differentials to the index price.

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

Our gathering and processing agreements provide for quarterly and annual MVCs. Under these MVCs, our producers agree to sell us, 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.

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We recognize customer obligations under their MVCs as revenue when our performance obligation has been met or when

it is remote the producer will be able to meet its MVC commitment.

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

		Year Ended December 31,
	Contract Type	2018		2017
Sales of natural gas (1)	Fixed Spread	$	322,209	$	379,423
Sales of NGLs and condensate (1)	Fixed Spread	220,480		179,247
Transportation, gathering and processing fees	Fixed Fee	55,516		53,762
Producer fees (2)	Fixed Fee	—		34,456
Treating and compression	Fixed Fee	14,740		15,451
Other	N/A	5,188		3,610
Total revenues		$	618,133	$	665,949

(1) Commodity-sensitive revenues are included in these categories as well.

(2) As a result of the FASB issuance of ASC 606, we identified certain natural gas purchase contracts that contained

producer fees which were previously recognized as revenue for services provided to producers. The fee revenue which

was previously presented within revenue now is presented within the costs of natural gas and liquids sold line item

within the condensed consolidated statement of operations beginning on January 1, 2018. Therefore, beginning on

January 1, 2018, the producer fee revenue of $26.6 million for the year ended December 31, 2018, respectively, that were previously recognized as revenue under ASC 605 are recognized as reductions to the costs of natural gas and liquids sold line item within the condensed consolidated statement of operations.

12. INVESTMENTS IN JOINT VENTURES

We own equity interests in two joint ventures with Targa as our joint venture partner. We own a 50% or less equity interest in each of the two 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.

We previously had a third joint venture arrangement with T2 Cogen which operated a cogeneration facility next to our Lone Star plant with similar terms that we accounted for as an equity method investment. On December 31, 2018, Targa and the Partnership as part of a statement of agreement, agreed to terminate the T2 Cogen joint venture and distributed one cogeneration unit to Targa, and the Partnership received 100% interest in T2 Cogen. Therefore, as of the effective date of December 31, 2018, T2 Cogen was no longer accounted for as an equity method investment and was consolidated into the Partnership. In addition, under the terms of the agreement, T2 Eagle Ford and T2 LaSalle will be operated by Targa after the completion of a transition period. Our indirect ownership percentages will remain the same with respect to T2 Eagle Ford and T2 LaSalle, and therefore continue to be accounted for as equity method investments.

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The joint ventures’ summarized financial data from their statements of operations for the years ended December 31, 2018 and 2017 is as follows (in thousands):

	Year Ended December 31,
	2018			2017
Revenue
T2 Eagle Ford	$	4,084		$	4,319
T2 Cogen	1,654			421
T2 LaSalle	1,409			1,619
Net loss
T2 Eagle Ford	$	(18,680	)	$	(19,454	)
T2 Cogen	(3,058		)	(3,730		)
T2 LaSalle	(5,928		)	(5,872		)

Our equity in losses of joint venture investments is comprised of the following for the years ended December 31, 2018 and 2017 (in thousands):

	Year Ended December 31,
	2018			2017
T2 Eagle Ford	$	(9,340	)	$	(9,727	)
T2 Cogen	(1,529		)	(1,865		)
T2 LaSalle	(1,482		)	(1,468		)
Equity in losses of joint venture investments	$	(12,351	)	$	(13,060	)

Our investments in joint ventures is comprised of the following as of December 31, 2018 and 2017 (in thousands):

	December 31, 2018		December 31, 2017
T2 Eagle Ford	$	83,332	$	92,248
T2 Cogen	—		4,425
T2 LaSalle	13,648		15,074
Investments in joint ventures	$	96,980	$	111,747

The joint ventures’ summarized balance sheets as of December 31, 2018 and 2017 is as follows (in thousands):

	December 31, 2018		December 31, 2017
T2 Eagle Ford
Current assets	$	3,435	$	2,150
Property, plant and equipment, net	166,667		185,399
Total assets	170,102		187,549
Total liabilities	2,590		2,146
Total equity	167,512		185,403
Total liabilities and equity	$	170,102	$	187,549
T2 LaSalle
Current assets	$	828	$	801
Property, plant and equipment, net	54,655		60,583
Total assets	55,483		61,384
Total liabilities	774		971
Total equity	54,709		60,413
Total liabilities and equity	$	55,483	$	61,384

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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.

Our top ten customers, excluding affiliates, for the years ended December 31, 2018 and 2017 represent the following percentages of consolidated revenue: 

	Year Ended December 31,
	2018		2017
Top ten customers	40.9	%	46.4	%

We did not have any customers, excluding affiliates, exceed 10% of total consolidated revenue for the years ended December 31, 2018 and 2017. However, with the sale of Robstown to EPIC in November 2018, the associated revenues from these NGL purchase and sale agreements will no longer be accounted for as affiliate revenue and will now be accounted for as third party revenue beginning on October 1, 2018. Therefore, we anticipate EPIC exceeding this threshold in 2019.

For the years ended December 31, 2018 and 2017, we did not experience significant nonpayment for services. We had no allowance for uncollectible accounts receivable at December 31, 2018 and 2017.

14. SUBSEQUENT EVENTS

Chapter 11 Proceedings

On April 1, 2019, the Partnership, General Partner and the Filing Subsidiaries filed voluntary petitions for relief under the Bankruptcy Code in the Bankruptcy Court. The Debtors have filed with the Bankruptcy Court motions seeking a variety of first-day relief, which are designed primarily to minimize the impact of the Chapter 11 proceedings on our operations, customers and employees and includes a motion to obtain post-petition financing. We will continue to operate our businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. We expect to continue our operations without interruption during the pendency of the Chapter 11 proceedings.

Impact on indebtedness

As of February 28, 2019, we had approximately $527.1 million in principal amount of indebtedness. The filing of the Chapter 11 Cases described above constituted an event of default that accelerated our obligations under the following debt instruments:

• the Third A&R Revolving Credit Agreement;

• the Term Loan Agreement; and

• the Investments Notes.

These debt instruments provide that as a result of the commencement of the Chapter 11 Cases, the principal and interest due thereunder shall be immediately due and payable. Any efforts to enforce such payment obligations under the debt instruments are automatically stayed as a result of the commencement of the Chapter 11 Cases, and the creditors’ rights of enforcement in respect of the debt instruments are subject to the applicable provisions of the Bankruptcy Code.

On April 1, 2019, we filed a motion seeking entry of an order authorizing the Debtors to enter into the DIP Financing to, among other things, provide additional liquidity to fund our operations during the Chapter 11 process.

Pursuant to a Commitment Letter dated as of March 31, 2019 and the DIP Credit Agreement and the DIP Facility, to be entered into by the Loan Parties, the DIP Lenders, the DIP L/C Issuers, and the DIP Agent, the DIP Lenders have agreed to provide to the Loan Parties the DIP Financing in an aggregate principal amount of $255 million, consisting of (i) the DIP New Money Loan and (ii) the DIP LC Loan (collectively, the DIP Term Loans) to cash collateralize the DIP L/C Facility, and (iii) a senior secured priming superpriority term loan in the aggregate principal amount of $127.5 million, which will be subject and

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subordinate to the DIP New Money Facility and the DIP L/C Facility, to refinance dollar-for-dollar term loans outstanding under the DIP Loans. The DIP Loans are subject to approval by the Bankruptcy Court. The proceeds of the DIP Loans will be used for purposes permitted by the Bankruptcy Court and the DIP Credit Agreement, including (i) working capital and other general corporate purposes of the Loan Parties, including the refinancing of certain term loans and letters of credit, (ii) to pay transaction costs, professional fees, and other obligations and expenses incurred in connection with the DIP Facilities, the Chapter 11 Cases, and the transactions contemplated thereunder, and (iii) to make adequate protection payments to Southcross’s creditors under the Senior Credit Facilities to the extent set forth in any order entered by the Bankruptcy Court.

The DIP Facilities will mature on the earliest of (i) the date that is six months after the Petition Date (subject to one three month extension with the consent of the DIP Lenders constituting the required lenders under the DIP Facility), (ii) the effective date of a chapter 11 plan, (iii) the date on which all or substantially all of the assets of the Loan Parties are sold in a sale under a chapter 11 plan or pursuant to Section 363 of the Bankruptcy Code, and (iv) the date the DIP Facilities are accelerated following an event of default thereunder.  Subject to certain exceptions, the DIP Facility will be secured by a senior perfected security interest in substantially all of the assets of the Loan Parties, including the collateral securing the Senior Credit Facilities and any other previously unencumbered assets.

Automatic stay

Subject to certain specific exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial or administrative actions against the Partnership and the Filing Subsidiaries as well as efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. As a result, for example, most creditor actions to obtain possession of property from us or any of the Filing Subsidiaries, or to create, perfect or enforce any lien against our property or any of the Filing Subsidiaries, or to collect on or otherwise exercise rights or remedies with respect to a pre-petition claim are stayed.

Executory contracts

Subject to certain exceptions, under the Bankruptcy Code, the Partnership and the Filing Subsidiaries may assume, assume and assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and fulfillment of certain other conditions. The rejection of an executory contract or unexpired lease is generally treated as a breach as of the petition date of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Partnership and the Filing Subsidiaries of performing their future obligations under such executory contract or unexpired lease but may give rise to a general unsecured claim against us or the applicable Filing Subsidiaries for damages caused by such rejection. The assumption of an executory contract or unexpired lease generally requires the Partnership and the Filing Subsidiaries to cure existing monetary or other defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Any description of the treatment of an executory contract or unexpired lease with the Partnership or any of the Filing Subsidiaries, including any description of the obligations under any such executory contract or unexpired lease, is qualified by and subject to any rights we have with respect to executory contracts and unexpired leases under the Bankruptcy Code.

Chapter 11 filing impact on creditors and unitholders

Under the priority requirements established by the Bankruptcy Code, unless creditors agree otherwise, post-petition liabilities to creditors and pre-petition liabilities must be satisfied in full before the holders of our existing common shares are entitled to receive any distribution or retain any property under a Chapter 11 plan. The ultimate recovery to creditors and unitholders, if any, will not be determined until confirmation and implementation of a Chapter 11 plan. The outcome of the Chapter 11 Cases remains uncertain at this time and, as a result, we cannot accurately estimate the amounts or value of distributions that creditors may receive.

Risks associated with Chapter 11 proceedings

For the duration of the of the Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to significant risks and uncertainties associated with Chapter 11 proceedings. As a result of these significant risks and uncertainties, our assets, liabilities, unitholders’ equity (deficit), officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in these financial statements may not accurately reflect our operations, properties and capital plans following the Chapter 11 proceedings.

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Delisting of Common Units

On February 27, 2019, the NYSE notified the Partnership that the staff of NYSE Regulation, Inc. (the “NYSE Regulation”) had determined to commence proceedings to delist our common units. The NYSE Regulation reached its decision to delist our common units pursuant to Rule 802.01C of the NYSE’s Listed Company Manual, as the Partnership’s unit price had fallen below the NYSE’s continued listing standard with average closing price of less than $1.00 over a consecutive 30 trading-day period and failed to cure this non-compliance within the required timeframe. The NYSE also suspended after the market close on the NYSE on February 27, 2019.

Effective February 28, 2019, our common units commenced trading on the OTCQX Marketplace under the ticker symbol “SXEE”. On March 20, 2019, the NYSE filed with the SEC a notification of removal from listing and registration on Form 25 to delist our common units and terminate the registration of our common units under Section 12(b) of the Securities Exchange Act of 1934. The delisting became effective on April 1, 2019.

15. SUPPLEMENTAL INFORMATION

Supplemental Cash Flow Information (in thousands)

	Year Ended December 31,
	2018		2017
Supplemental Disclosures:
Cash paid for interest	$	38,458	$	35,142
Cash paid for taxes	1		4
Supplemental schedule of non-cash investing and financing activities:
Accounts payable related to capital expenditures	1,075		1,042
Capital lease obligations	535		140
Class B Convertible unit in-kind distributions	1,785		3,188

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,
	2018			2017
Total interest costs	$	43,857		$	38,723
Capitalized interest included in property, plant and equipment, net	(412		)	(542		)
Interest expense	$	43,445		$	38,181

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, 2018 were as follows: $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, 2018 and 2017, 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 $1.7 million and $1.0 million for the years ended December 31, 2018 and 2017, respectively. Deferred revenue associated with these agreements was $11.1 million and $11.6 million at December 31, 2018 and 2017, respectively.

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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, 2018.

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, 2018, 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, 2018.

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, 2018. 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, 2018, that has materially affected, or is reasonably likely to affect materially, our internal control over financial reporting.

Item 9B. Other Information

Bankruptcy Filing

As previously discussed, on April 1, 2019, Southcross Energy Partners, L.P. (the “Partnership”), Southcross Energy Partners GP, LLC, the general partner of the Partnership (the “General Partner”) and certain of the Partnership’s subsidiaries, including, Southcross Energy Finance Corp., Southcross Energy Operating, LLC, Southcross Energy GP, LLC, Southcross Energy LP, LLC, Southcross Gathering Ltd., Southcross CCNG Gathering Ltd., Southcross CCNG Transmission Ltd., Southcross Marketing Company Ltd., Southcross NGL Pipeline Ltd., Southcross Midstream Services, L.P., Southcross Mississippi Industrial Gas Sales, L.P., Southcross Mississippi Pipeline, L.P., Southcross Gulf Coast Transmission Ltd., Southcross Mississippi Gathering, L.P., Southcross Delta Pipeline LLC, Southcross Alabama Pipeline LLC, Southcross Nueces Pipelines LLC, Southcross Processing LLC, FL Rich Gas Services GP, LLC, FL Rich Gas Services, LP, FL Rich Gas Utility GP, LLC, FL Rich Gas Utility, LP, Southcross Transmission, LP, T2 EF Cogeneration Holdings, LLC, and T2 EF Cogeneration LLC (collectively the “Filing Subsidiaries” and, together with the General Partner and the Partnership, the “Debtors”) filed a voluntary petition for relief (the "Bankruptcy Filing") under Chapter 11 of title 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). The Debtors have proposed to jointly administer their Chapter 11 cases under the caption In re Southcross Energy Partners, L.P., Case No. 19-10702 (the “Chapter 11 Cases”). The Debtors will continue to operate their businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

The Debtors have filed with the Bankruptcy Court motions seeking a variety of “first-day” relief, which are designed primarily to minimize the impact of the Chapter 11 proceedings on our operations, customers and employees, and includes a motion to obtain post-petition financing. We expect to continue our operations without interruption during the pendency of the Chapter 11 proceedings.

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All documents filed with the Bankruptcy Court are available for inspection at the Office of the Clerk of the Bankruptcy Court. You may also find information at our claims agent at www.kccllc.com.

On April 1, 2019, we filed a motion seeking entry of an order authorizing the Debtors to enter into the Debtor-in-Possession financing (“DIP Financing”) to, among other things, provide additional liquidity to fund our operations during the Chapter 11 process.

Pursuant to a Commitment Letter  dated as of March 31, 2019 and Form Credit Agreement attached thereto (the “DIP Credit Agreement” and, the facility thereunder, the “DIP Facility”), to be entered into by  Southcross, as borrower, its direct and indirect Debtor subsidiaries, as guarantors (the “Guarantors” and, together with Southcross, the “Loan Parties”), certain of our creditors under the Senior Credit Facilities, as lenders (the “DIP Lenders”) and letter of credit issuers (the “DIP L/C Issuers”), and Wilmington Trust, National Association, as administrative agent (the “DIP Agent”), the DIP Lenders have agreed to provide to the Loan Parties the DIP Financing in an aggregate principal amount of $255 million, consisting of (i) a senior secured priming superpriority term loan in the aggregate principal amount of $72.5 million (the “DIP New Money Loan”), (ii) a senior secured priming superpriority term loan in the aggregate principal amount of $55 million (the “DIP LC Loan” and, together with the DIP New Money Loans, the “DIP Term Loans”) to cash collateralize a letter of credit sub-facility for the issuance of letters of credit by certain issuing banks that will be party to the DIP Credit Agreement (the “DIP L/C Facility”), and (iii) a senior secured priming superpriority term loan in the aggregate principal amount of $127.5 million, which will be subject and subordinate to the DIP New Money Facility and the DIP L/C Facility, to refinance dollar-for-dollar term loans outstanding under the Term Loan Agreement owed to the DIP Lenders (the “DIP Roll-Up Loan” and, together with the DIP Term Loans, the “DIP Loans”).  The DIP Loans are subject to approval by the Bankruptcy Court.  The proceeds of the DIP Loans will be used for purposes permitted by the Bankruptcy Court and the DIP Credit Agreement, including (i) working capital and other general corporate purposes of the Loan Parties, including the refinancing of certain term loans and letters of credit, (ii) to pay transaction costs, professional fees, and other obligations and expenses incurred in connection with the DIP Facilities, the Chapter 11 Cases, and the transactions contemplated thereunder, and (iii) to make adequate protection payments to Southcross’s creditors under the Senior Credit Facilities to the extent set forth in any order entered by the Bankruptcy Court.

The DIP Facilities will mature on the earliest of (i) the date that is six months after the Petition Date (subject to one three month extension with the consent of the DIP Lenders constituting the required lenders under the DIP Facility), (ii) the effective date of a chapter 11 plan, (iii) the date on which all or substantially all of the assets of the Loan Parties are sold in a sale under a chapter 11 plan or pursuant to Section 363 of the Bankruptcy Code, and (iv) the date the DIP Facilities are accelerated following an event of default thereunder.  Subject to certain exceptions, the DIP Facility will be secured by a senior perfected security interest in substantially all of the assets of the Loan Parties, including the collateral securing the Senior Credit Facilities and any other previously unencumbered assets.

The filing of the Chapter 11 Cases constitutes an event of default that accelerated the Partnership’s obligations under the following debt instruments (the “Debt Instruments”):

• 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, as amended;

• 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; and

• $15.0 million aggregate principal amount of Qualifying Notes dated January 22, 2018, issued by the Partnership to each of certain funds or accounts managed or advised by EIG Global Energy Partners and certain funds or accounts managed or advised by Tailwater Capital LLC.

Departure of Chief Commercial Officer

On March 26, 2019, Joel M. Moxley, Senior Vice President and Chief Commercial Officer of the General Partner, t notified the General Partner and the Partnership of his intention to resign from the position of Senior Vice President and Chief Commercial Officer of the General Partner to pursue other opportunities, effective April 5, 2019.

In connection with his resignation, the General Partner and Mr. Moxley entered into a consulting agreement (the “Consulting Agreement”), effective as of March 26, 2019 (the “Effective Date”). Pursuant to the Consulting Agreement, (i) from the Effective Date until April 5, 2019, Mr. Moxley will continue perform the duties contemplated by his position as Chief Commercial Officer and provide for the transition of his duties to others, as needed (during which time he will continue to receive his annual salary); and (ii) from April 5, 2019 to July 12, 2019, Mr. Moxley will provide certain consulting services to

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the General Partner. Mr. Moxley will be entitled a weekly retainer in the amount of $7,864 paid in monthly lump sums for the consulting services he will provide to the General Partner. In addition, for a six month period beginning on May 1, 2019, the General Partner will pay COBRA on behalf of Mr. Moxley for the continuation of his and his covered dependents’ medical, dental, and/or vision benefits through COBRA. Under the terms of the Consulting Agreement, Mr. Moxley waives any severance or termination payments to which he may otherwise become entitled to under the terms of that certain Severance Agreement by and between Mr. Moxley and the General Partner dated June 15, 2005 (including any amendments thereto) or under the General Partner’s Employee Protection Plan. All other payments, benefits, incentive compensation, and awards promised to Mr. Moxley by the General Partner shall cease as of the Effective Date. The Consulting Agreement also contains a general release in favor of the General Partner, its subsidiaries and its ultimate parent.

The foregoing is a summary only and does not purport to be a complete description of all the terms, provisions, covenants and agreements contained in the Consulting Agreement, and is subject to and qualified in its entirety by reference to the complete text of the Consulting Agreement, a copy of which is filed as Exhibit 10.39 to this Annual Report on Form 10-K and is incorporated by reference herein.

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 participate, directly or indirectly, 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 a stock exchange are required to have a majority of independent directors serving on the board of directors of the listed company, the OTCQX 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. However, we intend to follow good corporate governance and the board of directors of our General Partner has determined that each of Messrs. Pinkerton, Caruso, and Cameron are independent as defined under the independence standards established by the NYSE and the Exchange Act.

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. Caruso 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.

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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. The OTCQX requires that our General Partner have at least two 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.

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 as of March 29, 2019.

Name	Age	Position with Southcross Energy Partners GP, LLC
James W. Swent III	68	Chairman, President and Chief Executive Officer
Michael B. Howe	52	Senior Vice President, Chief Financial Officer and Principal Accounting Officer
William C. Boyer	63	Senior Vice President and Chief Operating Officer
Joel D. Moxley*	60	Senior Vice President and Chief Commercial Officer
Kelly J. Jameson	54	Senior Vice President, General Counsel and Corporate Secretary
David W. Biegler	72	Director
Andrew A. Cameron	59	Director
Nicholas J. Caruso	73	Director
Jason H. Downie	48	Director
Randall W. Wade	48	Director
Jerry W. Pinkerton	78	Director

* Mr. Moxley tendered his resignation effective April 5, 2019. See Part II, Item 9B - "Other Information - Departure of Chief Commercial Officer" for a more detailed discussion.

James W. Swent III

James W. Swent III was elected as Chairman, President and Chief Executive Officer of our General Partner on September 17, 2018.

Prior to joining our General Partner and Holdings GP, Mr. Swent served as the Chairman of the Board, President and Chief Executive Officer of Paragon Offshore Limited from July 2017 to April 2018, a global supplier of offshore jack up contract drilling services. From July 2003 to December 2015, he was Executive Vice President and Chief Financial Officer of Ensco plc, a global provider of offshore contract drilling services. He joined Ensco in July 2003 as Senior Vice President and Chief Financial Officer and retired in December 2015. Mr. Swent previously held various financial executive positions in the information technology, telecommunications and manufacturing industries, including positions with Memorex Corporation and Nortel Networks. He served as Chief Executive Officer and Chief Financial Officer of Cyrix Corporation from 1996 to 1997 and Chief Financial Officer and Chief Executive Officer of American Pad and Paper Company from 1998 to 2000. Prior to joining Ensco plc, Mr. Swent served as Co-Founder and Managing Director of Amrita Holdings, LLC.

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Mr. Swent received a bachelor's degree in Finance and a master’s degree in Business Administration from the University of California at Berkeley. He currently serves on the Board of HGIM. Corp. and he previously served on the boards of Energy XXI Gulf Coast Inc., Co-Chairman of American Pad & Paper Co., Cyrix Corp, and Rodime PLC.

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, 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.

Michael B. Howe

Michael B. Howe was appointed Senior Vice President and Chief Financial Officer of our General Partner on January 4, 2019. Mr. Howe also assumed the responsibilities of principal accounting officer.

Mr. Howe, served as Chief Financial Officer of Medical Benevolence Foundation from July 2016 to September 2017. Prior to joining the Company and from December 2015 to June 2016, Mr. Howe served in Christian ministries, including as a volunteer minister with the Texas Department of Criminal Justice. From February 2009 to November 2015, Mr. Howe worked for Ensco PLC (NYSE: ESV) during which time he served in various positions including, as Vice President - Strategy (December 2014 to November 2015), Vice President - Human Resources (November 2012 to December 2014), Vice President - Finance (May 2011 to November 2012), and Treasurer (February 2009 to May 2011). Prior to joining Ensco PLC, Mr. Howe served as Assistant Treasurer for Devon Energy Corporation (NYSE: DVN) from December 2002 to February 2009 and as a Commercial Director at Enron Corporation from May 1997 to December 2001. Mr. Howe holds a Bachelor of Science in Accounting from Oklahoma State University and a Master in Business Administration from the University of Texas at Austin. He is a Certified Public Accountant.

William C. Boyer

William C. Boyer was appointed Senior Vice President and Chief Operating Officer of our General Partner on February 1, 2019. Prior to being elected Senior Vice President and Chief Operating Officer of the General partner, Boyer served as Senior Vice President of Operations of the General Partner since 2017 and previously served as Vice President of Operations of the General Partner since 2015.

Before joining the General Partner, Mr. Boyer served as General Manager of Oxy Midstream Operating Company (“Oxy”), a company specializing in midstream services of petroleum products, from 2014 to 2015. In his role at Oxy, Mr. Boyer oversaw the operations, safety, compliance and overall P&L for all of Occidental’s midstream businesses including Centurion Pipeline, its crude oil trucking, its NGL railcar terminal, and its propane and crude oil marine terminal businesses in Ingleside, Texas. Prior to joining Oxy, Mr. Boyer served as President of Centurion Pipeline from 2010 to 2014 where he led the operations, planning, risk management, safety and regulatory functions of the business. Concurrent with his role at Oxy, Mr.

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Boyer also served as President of Occidental Energy Transportation, a wholly-owned crude oil trucking subsidiary within Occidental Petroleum that gathered and transported crude oil in New Mexico and Texas. Prior to such roles, Mr. Boyer held various leadership positions at Occidental Petroleum Corporation over a span of 30 years, including Occidental of Elk Hills in California, Occidental Chemical Corporation in Houston, and Occidental Petroleum’s natural gas businesses at various locations. Mr. Boyer holds a Bachelor of Science in Chemical Engineering from the University of Oklahoma.

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 the Chairman, President and Chief Executive Officer of our General Partner from August 16, 2018 to September 17, 2018 and served as acting Chairman, President and Chief Executive Officer from March 2018 to September 2018, Mr. Biegler served as the 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 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. Mr. Biegler was selected to serve as a director on the board due to his financial and business expertise.

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 from October 2017 until February 2018 when he

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became the Chief Financial Officer. 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 and Compensation Committee, and Chairman of the Conflicts 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 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 when Holdings LP became the indirect owner of 100% of the General Partner (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.

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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 previously served as 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 56 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 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. 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.

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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, 2018.

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 2018:

• James W. Swent III, Chairman, President and Chief Executive Officer;

• David W. Biegler, Former Chairman, President and Chief Executive Officer;

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

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

• Bret M. Allan, Former 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 2018 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; and (iii) 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 March 4, 2018, Mr. Williamson was unable to act in his capacity as President and Chief Executive Officer of our General Partner and Mr. Biegler was elected as acting Chairman, President and Chief Executive Officer of our General Partner.

Effective September 17, 2018, Mr. Biegler stepped down as acting Chairman, President and Chief Executive Officer of our General Partner after serving as acting Chairman, President and Chief Executive Officer of our General Partner from March 4, 2018 to August 16, 2018 and Mr. Swent was elected as Chairman, President and Chief Executive Officer of our General Partner. Mr. Biegler continues to serve as a director of the 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

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competitive. In 2018, these compensation programs for executive officers consisted of base salary and bonus awards, 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, and (iv) 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 2018. 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 2018, the board of directors of our General Partner granted bonuses to Joel Moxley each in the amount of $297,750.

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 2018, we provided an employer match under our 401(k) Plan equal to 100% of employee contributions up to 6% of eligible compensation, subject to the annual maximum contribution limit imposed by the Internal Revenue Service. None of our Named Executive Officers participated in any defined benefit pension plans or non-qualified deferred compensation plans.

Severance Agreements.    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. We maintain bonus agreements which 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. Additionally, in 2018 the General Partner entered into an employment agreement with Mr. Swent that provides that Mr. Swent 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 in the employment agreement therein), so long as Mr. Swent remains employed by our General Partner through the date of the Change of Control. Furthermore, in 2018 our General Partner entered into retention agreements with Messrs. Moxley and Allan which provided that such Named Executive Officer will be eligible to receive a one-time lump sum cash payment (i) so long as such Named Executive Officer remained employed by our General partner through December 31, 2018, (ii) in the event of a Change of Control (as defined in the retention agreement therein) or (iii) such Named Executive Officer is involuntarily terminated by the General Partner without cause prior to December 31, 2018. Please see the section below entitled “Potential

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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 (as defined below) 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.

2018 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, 2017 and 2018:

Name and Principal Position	Year	Salary ($)	Bonus($)(1)	All other compensation ($)(2)	Total ($)
James W. Swent III(3)	2018	250,000	2,377,540	595	2,628,135
Chairman, President and Chief Executive Officer	2017	—	—	—	—
David W. Biegler(4)	2018	278,333	—	17,451	295,784
Former Chairman, President and Chief Executive Officer	2017	—	—	—	—
Bruce A. Williamson(5)	2018	343,230	—	405,789	749,019
Former Chairman, President and Chief Executive Officer	2017	1,000,000	—	16,827	1,016,827
Joel D. Moxley (6)	2018	397,000	1,093,000	17,871	1,507,871
Senior Vice President and Chief Commercial Officer	2017	397,000	457,750	16,884	871,634
Bret M. Allan	2018	330,000	1,005,700	16,978	1,352,678
Former Senior Vice President and Chief Financial Officer	2017	330,000	377,500	16,884	724,384

_______________________________________________________________________________

(1) For 2018, includes a $150,000 retention bonus and a $450,000 change of control bonus paid to Mr. Allan, a $150,000 retention bonus and a $450,000 change of control bonus paid to Mr. Moxley and a $2,377,540 change of control bonus paid to Mr. Swent. For 2018, includes $160,000 paid to Mr. Moxley representing a third of his 2016 Cash LTIP award which vested on April 1, 2018; and $130,000 paid to Mr. Allan representing a third of his 2016 Cash LTIP award which vested on April 1, 2018. For 2018, includes $18,600 which represents the fair-value of LTIP awards to Mr. Allan based on the closing price on July 1, 2018 and $9,600 bonus paid to Mr. Allan representing distribution equivalent rights. For 2018, includes $23,250, which represents the fair value of LTIP awards to Mr. Moxley, based on the closing price on July 1, 2018 and $12,000 bonus paid to Mr. Moxley representing distribution equivalent rights. For 2017, includes a $297,750 bonus paid to Mr. Moxley and a $247,500 bonus paid to Mr. Allan. For 2017, $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.

(2) For 2018, each of Allan, Moxley, Biegler and Williamson had a 401(k) match of $16,500. For 2018, includes life insurance premiums for Mr. Allan in the amount of $478, Mr. Moxley in the amount of $1,371, Mr. Biegler in the amount of $951, Mr. Williamson in the amount of $248 and Mr. Swent in the amount of $595. For 2018, Mr. Williamson had severance compensation in the total amount of $389,041. For 2017, each of Messrs. Williamson, Moxley and Allan had a 401(k) match of $16,200. For 2017, includes life insurance premiums for Mr. Williamson in the amount of $627 and Messrs. Moxley and Allan in the amount of $684 each.

(3) Mr. Swent was elected to our General Partner on September 17, 2018, as Chairman, President and Chief Executive Officer See our Current Report on Form 8-K filed with the SEC on September 18, 2018.

(4) Mr. Biegler was elected to our General Partner on March 4, 2018, as acting Chairman, President and Chief Executive Officer, as Mr. Williamson was unable to act in his capacity as President and Chief Executive Officer of our General Partner due to a medical leave of absence following a sudden illness. Mr. Biegler served as Chairman, President and Chief Executive Officer of our General Partner from August 16, 2018 until Mr. Swent's election on September 17, 2018. See our Current Report on Form 8-K filed with the SEC on March 5, 2018.

(5) Mr. Williamson stepped down from our General Partner effective August 16, 2018. See our Current Report on Form 8-K filed with the SEC on August 20, 2018.

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(6) Mr. Moxley's base salary is $408,910 effective March 11, 2019. Mr. Moxley tendered his resignation effective April 5, 2019. See Part II, Item 9B - "Other Information - Departure of Chief Commercial Officer" for a more detailed discussion.

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 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). All such phantom units granted to Messrs Moxley and Allan vested as of July 1, 2018.

Except for the LTIP awards with one-year vesting as indicated above, any 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 that would be granted to our Named Executive Officers is 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 herein, 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 5,393,738 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 2017 and 2018, there were no units granted under the LTIP to our Named Executive Officers. 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, 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.

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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.

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, 2018” 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, 2018

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, 2018:

	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
James W. Swent III	—
David W. Biegler	—
Bruce A. Williamson	—		—
Joel D. Moxley	—	(1)	—
Bret M. Allan	—	(2)	—

^{__________________________________________________________________________________________} 

(1) There are no longer any remaining 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 vested (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 and July 1, 2018.

(2) There are no longer any remaining 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 vested (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 and July 1, 2018.

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.

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Messrs. Moxley and Allan entered into severance agreements with our General Partner that provide for severance benefits upon certain terminations of employment. Mr. Swent entered into an employment agreement with our General Partner that provides for severance benefits upon certain terminations of his employment.

Mr. Swent’s Severance and Change in Control Benefits. On September 18, 2018, our General Partner entered into an employment agreement with Mr. Swent, the Chairman, President and Chief Executive Officer of our General Partner (the “Swent Employment Agreement”), which provides for an initial term through December 31, 2019, unless earlier terminated. Mr. Swent will receive an annualized base salary of $1,000,000 and will be eligible to receive an annual cash bonus based on certain performance targets in the amount of $500,000. Furthermore, Mr. Swent was eligible to receive a one-time lump sum cash payment in the event of a Change of Control (as such term is defined in the employment agreement therein), so long as Mr. Swent remains employed by our General Partner through the date of the Change of Control (the “Swent Bonus”). In 2018, the General Partner paid Mr. Swent a $2,377,540 Change of Control Bonus (as such term is defined in the employment agreement therein). Mr. Swent is also entitled to receive certain benefits and reimbursement of certain expenses.

Upon a termination of Mr. Swent’s employment by us for any reason, Mr. Swent is entitled to receive (i) any portion of his annual base salary through the date of termination not theretofore paid, (ii) any vested employee benefits through the date of termination not therefore paid, (iii) any expenses owed and (iv) any accrued and unused paid time off owed. Upon termination of Mr. Swent’s employment by us without cause or by Mr. Swent for good reason, the severance payment will be 70% of his current annual base salary. 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 12 months following termination and certain confidentiality provisions.

A for “cause” termination would occur under the Swent Employment Agreement if Mr. Swent (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 Swent Employment Agreement within 90 days after the following occurs (without Mr. Swent’s written consent): (i) Mr. Swent is removed as Chief Executive Officer or as a member of the board of directors of our General Partner, (ii) a material diminution of his base salary, (iii) a material breach of the Swent Employment Agreement by our General Partner, (iv) Mr. Swent is required to report directly to any other executive officer of our General Partner or (v) a change in the location of Mr. Swent’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. Swent is subject to certain non-competition and non-solicitation provisions set forth in the Swent Employment Agreement. Mr. Swent is also subject to certain confidentiality provisions during and after his employment.

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 former Chairman, President and Chief Executive of our General Partner (the “Williamson Employment Agreement”), which provided for an initial one year term, unless earlier terminated, that automatically extended for one year periods unless notice is given otherwise prior to the expiration of the then-current term. Mr. Williamson received an annualized base salary of $1,000,000 and was not eligible for any annual incentive bonus. Mr. Williamson was entitled to receive certain benefits and reimbursement of certain expenses.

Pursuant to the Williamson Employment Agreement, and upon his termination without "cause" effective on August 17, 2018, Mr. Williamson entered into an Severance Agreement and Release with the General Partner pursuant to which Mr. Williamson was entitled to receive a payment consisting of the balance of the then current term, through December 31, 2018.

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 the General Partner 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.

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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. Mr. Moxley does not have any unvested phantom units outstanding.

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. Effective August 16, 2018, and in connection with the termination of the Merger Agreement, the board of directors of our General Partner determined that Mr. Moxley will be entitled to receive $450,000 upon a Change of Control. Effective August 14, 2018, Mr. Moxley entered into a Retention Agreement with our General Partner which provided that Mr. Moxley would be eligible to receive a one-time lump sum cash payment in the amount of $150,000 (i) so long as Mr. Moxley remained employed by our General Partner through December 31, 2018, (ii) in the event of a Change of Control (as defined in the retention agreement therein) or (iii) Mr. Moxley is involuntarily terminated by the General Partner without cause prior to December 31, 2018. Mr. Moxley received his retention award as the condition set forth in (i) had been met.

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 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. Effective August 16, 2018 and in connection with the execution of the Merger Agreement, the board of our General Partner determined that Mr. Allan will be entitled to receive $450,000 upon a Change of Control. Effective August 14, 2018, Mr. Allan entered into a Retention Agreement with our General Partner which provided that Mr. Allan would be eligible to receive a one-time lump sum cash payment in the amount of $150,000 (i) so long as Mr. Allan remained employed by our General Partner through December 31, 2018, (ii) in the event of a Change of Control (as defined in the retention agreement therein) or (iii) Mr. Allan is involuntarily terminated by the General Partner without cause prior to December 31, 2018. The cash bonus payments will be allocated equally between the Partnership and Holdings. Mr. Allan received his retention award as the condition set forth in (i) had been met.

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. Mr. Biegler and Mr. Williamson received compensation as a non-employee 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 2018, our directors who are not officers, employees or paid consultants of our General Partner only received cash compensation. For 2018, 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 2018:

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

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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.

On January 17, 2019, the board of directors of our General Partner and Compensation Committee revised our Southcross Energy Partners GP, LLC Non-Employee Director Compensation Arrangement for the 2019 Fiscal Year. Specifically, directors are eligible for the following in 2019:

i. An annual retainer of $140,000, of which $75,000 is to be paid in January and $65,000 to be paid in equal installments 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. $1,500 for each Board meeting attended by all Board members, provided, however, that such amounts will not be paid to Board members that are employed by Tailwater Capital LLC ("Tailwater") or EIG Global Energy Partners ("EIG") or their affiliates; and

vi. $1,200 for each Committee meeting attended provided, however, that such amounts will not be paid to Board members that are employed by Tailwater Capital LLC or EIG Global Energy Partners or their affiliates.

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 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 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”). In connection with Mr. Williamson’s termination effective August 16, 2018, and pursuant to a settlement agreement between our General Partner’s and. Mr. Williamson, Mr. Williamson was credited 12,739 common units. On February 21, 2019, the Partnership GP Board terminated the Non-Employee Director Deferred Compensation Plan as Mr. Williamson had been the sole participant.

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. Wade 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. Wade as a result of being a director of our General Partner should be paid directly to EIG.

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Director Compensation for 2018

The following table presents the cash compensation earned, paid or awarded to each of our non-employee directors during the year ended December 31, 2018:

Name	Fees earned or paid in cash (1)		Cash awards		All other Compensation		Total
David W. Biegler	$	65,000	$	75,000	$	—	$	140,000
Jason H. Downie (1)	$	70,000	$	75,000	$	—	$	145,000
Jerry W. Pinkerton	$	95,625	$	75,000	$	—	$	170,625
Nicholas J. Caruso (2)	$	93,750	$	75,000	$	—	$	168,750
Andrew A. Cameron	$	80,000	$	75,000	$	—	$	155,000
Randall S. Wade (3)	$	65,000	$	75,000	$	—	$	140,000

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

(2) For Mr. Caruso, fees include a $10,000 one-time fee for additional responsibilities during CEO search and a $1,875 quarterly fee as chair of the Conflicts Committee. Mr. Caruso became chair of the Conflicts Committee in September 2018.

(3) Director associated with EIG. Cash compensation was paid to EIG.

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 March 20, 2019 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 March 20, 2019 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 48,694,891 common units, 12,213,713 subordinated units and 19,996,781 Class B Convertible Units outstanding as of March 20, 2019.

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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	54.4	%	12,213,713	100.0	%	19,996,781	100	%	72.3	%
5% Owners Not Listed Above or Below:
EIG BBTS Holdings, LLC(5)	26,492,074	54.4	%	12,213,713	100.0	%	19,996,781	100	%	72.3	%
TW Southcross Aggregator LP(6)	26,492,074	54.4	%	12,213,713	100.0	%	19,996,781	100	%	72.3	%
Directors and Named Executive Officers of Our General Partner:
David W. Biegler(2)	128,472	*		—	—		—	—		*
James W. Swent III(2)	—	*		—	—		—	—		*
Andrew A. Cameron(2)	—	—		—	—		—	—		—
Nicholas J. Caruso, Jr.(2)	6,454	*		—	—		—	—		*
Jason H. Downie(6)(7)	26,492,074	54.4	%	12,213,713	100.0	%	19,996,781	100	%	72.3	%
Joel D. Moxley(2)	20,294	*		—	—		—	—		*
Jerry W. Pinkerton(2)	14,739	*		—	—		—	—		*
Bruce A. Williamson(2)(8)	12,739	*		—	—		—	—		*
Randall Wade(5)(9)	26,492,074	54.4	%	12,213,713	100.0	%	19,996,781	100	%	72.3	%
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	%	19,996,781	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 March 20, 2019. 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 19,996,781 of our Class B Convertible Units.

(4) Based on a Schedule 13D/A filed with the SEC on November 16, 2018 and a Form 4 filed with the SEC on February 8, 2019. 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) 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. In accordance with the Non-Employee Director Deferred Compensation Plan and Mr. Williamson's termination as director of our General Partner, on August 22, 2018 Mr. Williamson received 12,739 phantom units and a cash payment of $101,667.67.

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(9) 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.

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

Securities Authorized for Issuance Under Equity Compensation Plan(1)

We have one compensation plan under which our common units are authorized for issuance, the LTIP. This equity compensation plan was approved by our unitholders. The following table sets forth certain information relating to the LTIP as of December 31, 2018:

	(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	—		5,343,738
Equity compensation plans not approved by security holders	—	—		—
Total	98,096	$	—	5,343,738

(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 March 20, 2019, Holdings owns 26,492,074 common units, 12,213,713 subordinated units and 19,996,781 Class B Convertible Units, representing a combined 72.6% 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 Holdings' former term loan 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 a group of Holdings' former term loan 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. 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.

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

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Operational Stage
Distributions to our General Partner and its affiliates	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 71% 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 subsequent quarter to reserve any excess cash for the operation of our business. 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, 2018, we incurred expenses related to these reimbursements, which are reflected in operating expenses in our consolidated statements of operations.

Recent Lack of Quarterly Distributions

The board of directors of our General Partner (the "Partnership GP Board") suspended paying a quarterly distribution with respect to the fourth quarter of 2015 and every quarter of 2016, 2017 and 2018 to conserve any excess cash for the operation of our business and due to restrictions imposed by our debt instruments.

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. James W. Swent III serves as Chairman of the Board as of September 17, 2018.

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, 2018 and 2017, we paid EIG and Tailwater $0.3 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, 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 of our General Partner and the Conflicts Committee.

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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 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. While the Partnership continues to have a G&P Agreement with Holdings, effective as of October 1, 2018, the NGL agreement was assigned to EPIC as described below.

We recorded revenues from affiliates of $216.5 million and $195.7 million for the years ended December 31, 2018 and 2017, 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 $6.0 million and $33.2 million as of December 31, 2018 and 2017, respectively, and accounts payable due to affiliates of $0.3 million and $0.4 million as of December 31, 2018 and 2017, 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, 2018.

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

On July 29, 2018, Holdings terminated the Contribution Agreement since the transactions contemplated thereby were not completed on or prior to June 15, 2018 due to AMID’s Funding Failure (as defined in the Contribution Agreement). Pursuant to the terms of the Contribution Agreement, AMID was obligated to pay Holdings a $17 million termination fee as a result of such termination. On August 1, 2018, AMID paid the $17 million termination fee to Holdings, of which $4.2 million was contributed to the Partnership and was used to reimburse the Partnership’s transaction costs.

On October 4, 2018, EPIC Midstream Holdings, LP (“EPIC”) and EPIC Y-Grade Holdings, LP, a subsidiary of EPIC,

entered into a definitive equity purchase agreement with Holdings and Holdings Borrower to acquire Holdings' Robstown fractionation facility ("Robstown") and related pipelines that enables the Robstown facility to receive natural gas liquids from various supply sources and several short pipelines that allow the delivery of fractionated products to Corpus Christi-area markets. Under the terms of the agreement, EPIC assumed all of the NGL purchase and sale agreements associated with the Robstown fractionator, including certain natural gas liquids sales and transportation agreements with the Partnership. Since these agreements are expected to remain in place for several years, we do not expect this transaction to have a material effect on the Partnership’s ongoing financial position. The sale was completed in November 2018.

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

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

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

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

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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, 2018 and 2017:

	Year ended December 31,
	2018		2017
Audit fees(1)	$	1,517,805	$	1,470,500
Audit-related fees(2)	10,000		75,000
Tax fees(3)	—		50,000
	$	1,527,805	$	1,595,500

(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 the bankruptcy and 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, 2018.

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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	75
Consolidated Balance Sheets as of December 31, 2018 and 2017	77
Consolidated Statements of Operations for the Years Ended December 31, 2018 and 2017	78
Consolidated Statements of Cash Flows for the Years Ended December 31, 2018 and 2017	79
Consolidated Statements of Changes in Partners' Capital (Deficit) for the Years Ended December 31, 2018 and 2017	80
Notes to Consolidated Financial Statements	81

(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
2.3	Amendment No. 1 to Merger Agreement dated as of June 1, 2018 by and among American Midstream Partners, LP, American Midstream GP, LLC, Southcross Energy Partners, L.P., Southcross Energy Partners GP, LLC and Cherokee Merger Sub LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K dated June 1, 2018).
2.4	Amendment No. 1 to Contribution Agreement dated as of June 1, 2018 by and among American Midstream Partners, LP, American Midstream GP, LLC, and Southcross Holdings LP (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K dated June 1, 2018).
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	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).
10.19#	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).
10.20#	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).
10.21#	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).
10.22#	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).
10.23	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).
10.24	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).
10.25	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).
10.26	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).
10.27#	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).
10.28#	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).
10.29#	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).
10.30	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).
10.31#	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).
10.32#	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).
10.33#	Severance Agreement and Release, dated August 17, 2018, between Southcross Energy Partners GP, LLC and Bruce A. Williamson (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated August 20, 2018).
10.34#	Form of Retention Agreement by and between Southcross Energy Partners GP, LLC and each of Bret M. Allan and Joel Moxley (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated September 12, 2018).
10.35#	Employment Agreement, dated September 17, 2018, between Southcross Energy Partners GP, LLC and James W. Swent III (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated September 18, 2018).
10.36#	Offer Letter executed December 20, 2018, by and between Southcross Energy Partners GP, LLC and Michael B. Howe (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated December 26, 2018).

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Exhibit Number	Description
10.37#	Severance Agreement, dated as of November 14, 2016, by and between Southcross Energy Partners GP, LLC and William C. Boyer (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated February 6, 2019).
10.38#	Form of Retention Bonus Arrangement Letter, dated as of March 13, 2019, by and between Southcross Energy Partners GP, LLC and each of William Boyer, Michael Howe and James W. Swent III (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated March 18, 2019).
10.39*#	Consulting Agreement Letter, dated as of March 27, 2019, by and between Southcross Energy Partners GP, LLC and Joel Moxley.
21.1*	List of Subsidiaries of Southcross Energy Partners, L.P.
31.1*	Certification of Chief Executive Officer required by Rule 13a-14(a)/15d-14(a).
31.2*	Certification of Chief Financial Officer required by Rule 13a-14(a)/15d-14(a).
32.1*	Certifications of Chief Executive Officer and Chief Financial Officer required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
101.INS*†	XBRL Instance Document
101.SCH*†	XBRL Taxonomy Extension Schema
101.CAL*†	XBRL Taxonomy Extension Calculation Linkbase
101.DEF*†	XBRL Taxonomy Extension Definition Linkbase
101.LAB*†	XBRL Taxonomy Extension Label Linkbase
101.PRE*†	XBRL Extension Presentation Linkbase

# Management contracts or compensatory plans or arrangement.

* Filed or furnished herewith.

† The financial information contained in the XBRL (eXtensible Business Reporting Language)-related documents is unaudited.

(c)   Financial Statement Schedules

Not applicable.

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:	April 1, 2019	By:	/s/ JAMES W. SWENT III
			James W. Swent III 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/ JAMES W. SWENT III	President, Chief Executive Officer and Chairman of the Board	April 1, 2019
James W. Swent III	(Principal Executive Officer)
/s/ MICHAEL B. HOWE	Senior Vice President and Chief Financial Officer	April 1, 2019
Michael B. Howe	(Principal Financial Officer and Principal Accounting Officer)
/s/ DAVID W. BIEGLER	Director	April 1, 2019
David W. Biegler
/s/ ANDREW A. CAMERON	Director	April 1, 2019
Andrew A. Cameron
/s/ NICHOLAS J. CARUSO	Director	April 1, 2019
Nicholas J. Caruso
/s/ JASON DOWNIE	Director	April 1, 2019
Jason Downie
/s/ JERRY W. PINKERTON	Director	April 1, 2019
Jerry W. Pinkerton
/s/ RANDALL S. WADE	Director	April 1, 2019
Randall S. Wade

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