Southcross Energy Partners 10-Q 2018 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 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	45-5045230
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1717 Main Street, Suite 5200 Dallas, TX	75201
(Address of principal executive offices)	(Zip Code)

(214) 979-3700

(Registrant’s telephone number, including area code) 

(Former name, former address and former fiscal year, if changed since last report)

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 ý 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 during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 o	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 o No ý

As of November 9, 2018, the registrant has 48,686,215 common units outstanding, 12,213,713 subordinated units outstanding and 19,314,797 Class B Convertible Units outstanding. Our common units trade on the NYSE under the symbol “SXE.”

Commonly Used Terms

As generally used in the energy industry and in this Quarterly Report on Form 10-Q, 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

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: 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 and 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, normal butane and natural gasoline

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FORM 10-Q

TABLE OF CONTENTS

Southcross Energy Partners, L.P.

PART I — FINANCIAL INFORMATION		4
ITEM 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017	4
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2018 and 2017	5
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2018 and 2017	6
	Condensed Consolidated Statements of Changes in Partners’ Capital for the Nine Months Ended September 30, 2018 and 2017	8
	Notes to Condensed Consolidated Financial Statements (Unaudited)	9
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	40
ITEM 4.	Controls and Procedures	40
PART II — OTHER INFORMATION		40
ITEM 1.	Legal Proceedings	40
ITEM 1A.	Risk Factors	41
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41
ITEM 3.	Defaults Upon Senior Securities	41
ITEM 4.	Mine Safety Disclosures	41
ITEM 5.	Other Information	41
ITEM 6.	Exhibits	41
SIGNATURES		42

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PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

SOUTHCROSS ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except for unit data)

(Unaudited)

	September 30, 2018		December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	3,048	$	5,218
Trade accounts receivable	23,193		33,920
Accounts receivable - affiliates	48,450		33,163
Prepaid expenses	1,662		2,592
Other current assets	8,113		497
Total current assets	84,466		75,390
Property, plant and equipment, net	869,547		914,547
Investments in joint ventures	102,652		111,747
Other assets	2,393		2,519
Total assets	$	1,059,058	$	1,104,203
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	51,086	$	57,782
Accounts payable - affiliates	36		378
Current portion of long-term debt	522,787		4,256
Other current liabilities	13,457		12,976
Total current liabilities	587,366		75,392
Long-term debt	—		514,266
Other non-current liabilities	17,300		14,979
Total liabilities	604,666		604,637
Commitments and contingencies (Note 6)
Partners' capital:
Common units (48,670,936 and 48,614,187 units outstanding as of September 30, 2018 and December 31, 2017, respectively)	184,839		215,146
Class B Convertible units (19,314,797 and 18,335,181 units issued and outstanding as of September 30, 2018 and December 31, 2017, respectively)	260,512		266,725
Subordinated units (12,213,713 units issued and outstanding as of September 30, 2018 and December 31, 2017, respectively)	643		8,302
General partner interest	8,398		9,393
Total partners' capital	454,392		499,566
Total liabilities and partners' capital	$	1,059,058	$	1,104,203

See accompanying notes.

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SOUTHCROSS ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except for per unit data)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Revenues:
Revenues	$	79,387		$	122,099		$	261,591		$	364,456
Revenues - affiliates	75,417			48,379			187,263			129,458
Total revenues (Note 10)	154,804			170,478			448,854			493,914
Expenses:
Cost of natural gas and liquids sold	118,377			136,723			346,305			388,362
Operations and maintenance	13,626			14,278			41,975			43,779
Depreciation and amortization	17,787			17,521			53,549			53,673
General and administrative	5,613			6,557			15,529			19,616
Impairment of assets	—			1,120			—			1,769
Loss (gain) on sale of assets, net	(84		)	186			(637		)	(5		)
Total expenses	155,319			176,385			456,721			507,194
Loss from operations	(515		)	(5,907		)	(7,867		)	(13,280		)
Other income (expense):
Equity in losses of joint venture investments	(3,161		)	(3,218		)	(9,449		)	(9,865		)
Interest expense	(11,158		)	(9,931		)	(32,263		)	(28,670		)
Gain on insurance proceeds	—			—			—			1,508
Total other expense	(14,319		)	(13,149		)	(41,712		)	(37,027		)
Loss before income tax expense	(14,834		)	(19,056		)	(49,579		)	(50,307		)
Income tax expense	—			(2		)	—			(4		)
Net loss	$	(14,834	)	$	(19,058	)	$	(49,579	)	$	(50,311	)
General partner unit in-kind distribution	(11		)	(20		)	(33		)	(50		)
Net loss attributable to partners	$	(14,845	)	$	(19,078	)	$	(49,612	)	$	(50,361	)
Earnings per unit:
Net loss allocated to limited partner common units	$	(8,833	)	$	(11,545	)	$	(29,659	)	$	(30,590	)
Weighted average number of limited partner common units outstanding	48,658			48,574			48,640			48,545
Basic and diluted loss per common unit	$	(0.18	)	$	(0.24	)	$	(0.61	)	$	(0.63	)
Net loss allocated to limited partner subordinated units	$	(2,217	)	$	(2,902	)	$	(7,446	)	$	(7,694	)
Weighted average number of limited partner subordinated units outstanding	12,214			12,214			12,214			12,214
Basic and diluted loss per subordinated unit	$	(0.18	)	$	(0.24	)	$	(0.61	)	$	(0.63	)

See accompanying notes.

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SOUTHCROSS ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited) 

	Nine Months Ended September 30,
	2018			2017
Cash flows from operating activities:
Net loss	$	(49,579	)	$	(50,311	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization	53,549			53,673
Unit-based compensation	210			1,241
Amortization of deferred financing costs, original issuance discount and PIK interest	4,143			2,719
Gain on sale of assets	(637		)	(5		)
Unrealized gain on financial instruments	(13		)	(15		)
Equity in losses of joint venture investments	9,449			9,865
Impairment of assets	—			1,769
Gain on insurance proceeds	—			(1,508		)
Other, net	(189		)	(411		)
Changes in operating assets and liabilities:
Trade accounts receivable, including affiliates	(4,559		)	12,503
Prepaid expenses and other current assets	(7,172		)	28
Other non-current assets	636			(22		)
Accounts payable and accrued liabilities, including affiliates	(7,687		)	(1,912		)
Other liabilities	5,188			(1,778		)
Net cash provided by operating activities	3,339			25,836
Cash flows from investing activities:
Capital expenditures	(9,694		)	(17,027		)
Aid in construction receipts	(7		)	8,876
Insurance proceeds from property damage claims, net of expenditures	—			2,000
Net proceeds from sales of assets	693			2,974
Investment contributions to joint venture investments	(354		)	(412		)
Net cash used in investing activities	(9,362		)	(3,589		)
Cash flows from financing activities:
Borrowings under our senior unsecured note	15,000			—
Repayments under our credit facility	(11,431		)	(24,000		)
Repayments under our term loan agreement	(3,192		)	(4,289		)
Payments on capital lease obligations	(461		)	(369		)
Financing costs	(256		)	(44		)
Tax withholdings on unit-based compensation vested units	(8		)	(119		)
Contribution from parent	4,201			—
Net cash provided by (used in) financing activities	3,853			(28,821		)
Net decrease in cash and cash equivalents	(2,170		)	(6,574		)
Cash and cash equivalents — Beginning of period	5,218			21,226
Cash and cash equivalents — End of period	$	3,048		$	14,652

See accompanying notes.

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SOUTHCROSS ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(In thousands)

(Unaudited)

	Partners' Capital
	Limited Partners
	Common			Class B Convertible			Subordinated			General Partner			Total
BALANCE - December 31, 2017	$	215,146		$	266,725		$	8,302		$	9,393		$	499,566
Net loss	(29,659		)	(11,483		)	(7,446		)	(991		)	(49,579		)
Unit-based compensation on long-term incentive plan	210			—			—			—			210
Contribution from parent	—			4,201			—			—			4,201
Tax withholdings on unit-based compensation vested units	(8		)	—			—			—			(8		)
Contributions from general partner	—			—			—			2			2
General partner unit in-kind distribution	(13		)	(6		)	(3		)	22			—
Class B Convertible unit in-kind distribution	(837		)	1,075			(210		)	(28		)	—
BALANCE - September 30, 2018	$	184,839		$	260,512		$	643		$	8,398		$	454,392

	Partners' Capital
	Limited Partners
	Common			Class B Convertible			Subordinated			General Partner			Total
BALANCE - December 31, 2016	$	255,124		$	278,508		$	19,240		$	10,757		$	563,629
Net loss	(30,560		)	(11,058		)	(7,687		)	(1,006		)	(50,311		)
Unit-based compensation on long-term incentive plan	1,241			—			—			—			1,241
Tax withholdings on unit-based compensation vested units	(119		)	—			—			—			(119		)
Contributions from general partner	—			—			—			5			5
Retention bonuses funded by Holdings	2,281			—			—			—			2,281
General partner unit in-kind distribution	(31		)	(11		)	(8		)	50			—
Class B Convertible unit in-kind distribution	(1,905		)	2,447			(479		)	(63		)	—
BALANCE - September 30, 2017	$	226,301		$	269,886		$	11,066		$	9,743		$	516,726

See accompanying notes.

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SOUTHCROSS ENERGY PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. ORGANIZATION AND DESCRIPTION OF BUSINESS

Organization

Southcross Energy Partners, L.P. (the "Partnership," "Southcross," "we," "our" or "us") is a Delaware limited partnership formed in April 2012. Our common units are listed on the New York Stock Exchange under the symbol “SXE.” We are a master limited partnership, headquartered in Dallas, Texas, that provides natural gas gathering, processing, treating, compression and transportation services and access to NGL fractionation and transportation services. We also source, purchase, transport and sell natural gas and NGLs. Our assets are located in South Texas, Mississippi and Alabama and include two gas processing plants, one fractionation facility, 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 consolidated lenders under Holdings' term loan (the "Lenders") own the remaining one-third of Holdings.

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”), as a result of the merger contemplated by the Merger Agreement not being 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”), as result of the transactions contemplated by the Contribution Agreement not being 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.

Letter Agreement. In connection with the Merger Agreement and Contribution Agreement, Holdings and the Partnership entered into a Letter Agreement (the “Letter Agreement”) providing for Holdings to reimburse the Partnership for all fees or expenses of the Partnership in connection with the Merger Agreement including (i) any fees or expenses of counsel, accountants, investment bankers and consultants retained by the Partnership or the conflicts committee of the Partnership, and (ii) the payment of any termination fee or the reimbursement of any AMID expense, in each case, if the Merger has not closed and (a) the Merger Agreement is terminated because the Contribution Agreement has been terminated under certain specified circumstances, including if the Contribution Agreement is terminated in a manner that results in Holdings being entitled to receive the termination fee, or (b) the Merger Agreement is terminated without the prior approval of the conflicts committee of the Partnership under certain specified circumstances. A portion of the termination fee referenced above was used to reimburse the Partnership’s transaction costs.

Liquidity Consideration

Our future cash flow may be materially adversely affected if the natural gas and NGL volumes connected to our systems decline. 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

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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. We remain focused on our efforts to improve future liquidity, and continue our cost-saving efforts to lower our operating and general and administrative cost structure. Additionally, we intend to capitalize on the improving commercial environment in our key operating areas as we pursue various strategic options to improve our balance sheet.

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 $120 million (then further reduced to $115 million on December 31, 2018) and the sublimit for letters of credit also was reduced from $75 million to $50 million (total aggregate commitments will be periodically further reduced through December 31, 2018); (ii) the Consolidated Total Leverage Ratio and Consolidated Senior Secured Leverage Ratio (each as defined in the Fifth Amendment) financial covenants were suspended until the quarter 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 are required to maintain minimum levels of Consolidated EBITDA (as defined in the Fifth Amendment) on a quarterly basis and are subject to certain covenants and restrictions related to liquidity and capital expenditures. See Note 5.

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.

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 5.

We continue to face a challenging corporate capital structure with substantial financial leverage and we remain focused on our overall profitability, including managing Partnership-wide, cost-savings initiatives.

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 “SXE GP Board”), together with our management, determined that in our current corporate capital structure and absent continued access to equity cures from our Sponsors or a significant equity infusion from a third party, neither of which the Partnership expects, or absent additional amendments to its Third A&R Revolving Credit Agreement (which is due August 4, 2019) or waivers of the March 31, 2019 requirement to comply with the Consolidated Total Leverage Ratio (as defined in the Fifth Amendment) and Consolidated Interest Coverage Ratio (as defined in the Sixth Amendment), the Partnership is not expected to be able to comply with such financial covenants in the next twelve months, which will trigger an event of default under the Senior Credit Facilities (as defined and discussed in Note 5). As a result of the Partnership’s expected inability to comply with its financial covenants twelve months from the issuance of this Form 10-Q, together with the maturity date of the Third A&R Revolving Credit Agreement being in less than twelve months, management has determined that there are conditions and events that raise substantial doubt about the Partnership’s ability to continue as a going concern.

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If we do not comply with the applicable covenants or if our independent registered public accounting firm reports in a subsequent audit report the existence of substantial doubt regarding our ability to continue as a going concern, then an event of default under the Senior Credit Facilities would occur which would trigger a cross default of Southcross Holdings Borrowers’ credit facilities. Such events of default, if not cured, would allow the lenders under each of these borrowing arrangements to accelerate the maturity of the debt, making it due and payable immediately and for which the Partnership does not have sufficient funds to repay upon an event of default or upon maturity.

Management is pursuing all reasonable options to generate liquidity and maintain compliance with the Partnership’s financial covenants and other commitments including refinancing its indebtedness and negotiating with its lenders for more favorable terms. Management cannot reasonably assure that it will be effective in implementing any such strategy, and consequently, has concluded that substantial doubt exists regarding SXE’s ability to continue as a going concern.

Basis of Presentation

We prepared this report under the rules and regulations of the Securities Exchange Commission (the “SEC”) and in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial statements. Accordingly, these condensed consolidated financial statements do not include all of the disclosures required by GAAP and should be read in conjunction with our 2017 Annual Report on Form 10-K (“2017 Annual Report on Form 10-K”). The condensed consolidated financial statements as of September 30, 2018 and December 31, 2017, and for the three and nine months ended September 30, 2018 and 2017, are unaudited and have been prepared on the same basis as the audited financial statements included in our 2017 Annual Report on Form 10-K. However, on January 1, 2018, the Partnership adopted Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”), using the modified retrospective method. Accordingly, our condensed consolidated financial statements for the three and nine months ended September 30, 2018 have been prepared in accordance with the updated accounting principles under the new standard. Adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the results of operations and financial position have been included herein. All intercompany accounts and transactions have been eliminated in the preparation of the accompanying condensed consolidated financial statements.

The accompanying unaudited condensed consolidated financial statements were prepared in conformity with GAAP, which 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 condensed consolidated financial statements and the reported amounts of revenues and expenses during the applicable period. Actual results may differ from those estimates. Information for interim periods may not be indicative of our operating results for the entire year.

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 13.

Segments

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

Significant Accounting Policies

During the nine months ended September 30, 2018, the Partnership adopted ASC 606. As a result, there was a change to our significant accounting policies described in Note 1 of our 2017 Annual Report on Form 10-K, as described below.

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. These changes will not have a material impact to our ongoing business operations.

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 condensed 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 condensed 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.

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 condensed consolidated financial statements. We are evaluating the impact of each pronouncement on our condensed consolidated financial statements.

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) should include payments to be made in optional periods only if the lessee is reasonably certain to exercise an option to extend the lease or not to exercise an option to terminate the lease. Similarly, optional payments to purchase the underlying asset should be included in the measurement of lease assets and lease liabilities only if the lessee is reasonably certain to exercise that purchase option. In addition, also consistent with the previous leases guidance, a lessee (and a lessor) should exclude most variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. 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 in the period of adoption. We have evaluated the majority of our lease agreements and are developing our implementation plan to assess the impact to our existing financial statement disclosures. The lease pronouncement will become effective beginning in 2019.

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2. 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 three and nine months ended September 30, 2018 and 2017 (in thousands, except unit and per unit data): 

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Net loss	$	(14,834	)	$	(19,058	)	$	(49,579	)	$	(50,311	)
General partner unit in-kind distribution	(11		)	(20		)	(33		)	(50		)
Net loss attributable to partners	$	(14,845	)	$	(19,078	)	$	(49,612	)	$	(50,361	)
General partner's interest(1)	$	(308	)	$	(396	)	$	(1,024	)	$	(1,019	)
Class B Convertible limited partner interest(1)	(3,487		)	(4,235		)	(11,483		)	(11,058		)
Limited partners' interest(1)
Common	$	(8,833	)	$	(11,545	)	$	(29,659	)	$	(30,590	)
Subordinated	(2,217		)	(2,902		)	(7,446		)	(7,694		)

(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.

	Three Months Ended September 30,						Nine Months Ended September 30,
Common Units	2018			2017			2018			2017
Interest in net loss	$	(8,833	)	$	(11,545	)	$	(29,659	)	$	(30,590	)
Effect of dilutive units - numerator (1)	—			—			—			—
Dilutive interest in net loss	$	(8,833	)	$	(11,545	)	$	(29,659	)	$	(30,590	)
Weighted-average units - basic	48,657,961			48,573,647			48,640,448			48,544,728
Effect of dilutive units - denominator (1)	—			—			—			—
Weighted-average units - dilutive	48,657,961			48,573,647			48,640,448			48,544,728
Basic and diluted net loss per common unit	$	(0.18	)	$	(0.24	)	$	(0.61	)	$	(0.63	)

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	Three Months Ended September 30,						Nine Months Ended September 30,
Subordinated Units	2018			2017			2018			2017
Interest in net loss	$	(2,217	)	$	(2,902	)	$	(7,446	)	$	(7,694	)
Effect of dilutive units - numerator(1)	—			—			—			—
Dilutive interest in net loss	$	(2,217	)	$	(2,902	)	$	(7,446	)	$	(7,694	)
Weighted-average units - basic	12,213,713			12,213,713			12,213,713			12,213,713
Effect of dilutive units - denominator(1)	—			—			—			—
Weighted-average units - dilutive	12,213,713			12,213,713			12,213,713			12,213,713
Basic and diluted net loss per subordinated unit	$	(0.18	)	$	(0.24	)	$	(0.61	)	$	(0.63	)

(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 87,388 and 86,418 unvested awards granted under the LTIP for the three months ended September 30, 2018 and 2017, respectively. The weighted average units that were not included in the computation of diluted per unit amounts were 230,833 and 46,551 unvested awards granted under the LTIP for the nine months ended September 30, 2018 and 2017, respectively.

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 5) 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 5.

The SXE GP Board suspended paying a quarterly distribution with respect to the fourth quarter of 2015, every quarter of 2016 and 2017 and the first, second and third quarters of 2018 to conserve any excess cash for the operation of our business. The SXE GP Board and our management believe this suspension to be in the best interest of our unitholders and will continue to evaluate our ability to reinstate the distribution in future periods. More importantly, we are restricted under the terms of the Fifth Amendment from paying a distribution until our Consolidated Total Leverage Ratio is below 5.0.

Paid In-Kind Distributions

Class B Convertible Units. As of September 30, 2018, the Class B Convertible Units consisted of 19,314,797 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 7.

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The following table represents the Class B PIK unit distribution paid on the Class B Convertible Units for the periods ended December 31, 2017 and September 30, 2018 (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
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.

3. 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 do not have financial assets and liabilities classified as Level 3.

In certain cases, the inputs used to measure fair-value may fall into different levels of the fair-value hierarchy. In such cases, the level in the fair-value hierarchy must be determined based on the lowest level input that is significant to the fair-value measurement. An assessment of the significance of a particular input to the fair-value measurement in its entirety requires judgment and consideration of factors specific to the asset or liability.

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable represent fair-values based on the short-term nature of these instruments. The fair-value of our Credit Facility (defined in Note 5) 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 September 30, 2018, the fair-value of our term loan was $388.9 million and the fair-value of the Investment Notes (defined in Note 5) was $14.8 million, based on recent trading levels and are considered Level 2 fair-value instruments.

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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	September 30, 2018
40,000	3.000	%	December 31, 2016	January 1, 2019	—
60,000	3.000	%	June 30, 2017	June 30, 2019	14
175,000	4.000	%	June 30, 2018	June 30, 2019	1
					$	15

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 in the balance sheets. There was no effect of offsetting in the balance sheets as of September 30, 2018 or December 31, 2017.

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
	September 30, 2018		December 31, 2017
Current interest rate derivative assets	$	15	$	1
Non-current interest rate derivative assets	—		1
Total interest rate derivatives	$	15	$	2

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2018			2017		2018			2017
Unrealized loss (gain) on interest rate derivatives	$	(12	)	$	5	$	(13	)	$	—
Realized gain on interest rate derivatives	—			—		—			(15		)

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4. LONG-LIVED ASSETS

Property, Plant and Equipment

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

	Estimated Useful Life (yrs)	September 30, 2018			December 31, 2017
Pipelines	15-30	$	574,870		$	571,730
Gas processing, treating and other plants	15	520,480			520,765
Compressors	5-15	79,093			78,997
Rights of way and easements	15	49,897			49,897
Furniture, fixtures and equipment	5	9,746			9,746
Capital lease vehicles	3-5	2,863			2,114
Total property, plant and equipment		1,236,949			1,233,249
Accumulated depreciation and amortization		(386,927		)	(334,528		)
Total		850,022			898,721
Construction in progress		5,871			2,173
Land and other		13,654			13,653
Property, plant and equipment, net		$	869,547		$	914,547

Depreciation is provided using the straight-line method based on the estimated useful life of each asset. Depreciation expense for the three and nine months ended September 30, 2018 was $17.8 million and $53.5 million, respectively, and $17.5 million and $53.7 million for the three and nine months ended September 30, 2017, respectively.

As part of Partnership-wide, cost-saving initiatives, management elected to idle the Bonnie View fractionation facility (“Bonnie View”) in the second quarter of 2017. As a result, all of our Y-grade product is being sold to Holdings in accordance with our affiliate Y-grade sales agreement and is being fractionated at the Holdings’ Robstown fractionation facility (“Robstown”). We utilize Bonnie View as a backup option to the extent Robstown is unable to fractionate our Y-grade product, however, during the third quarter of 2018, management elected to restart Bonnie View. Our election to restart Bonnie View has not had a material impact to our third quarter 2018 earnings and cash flows.

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 5), we used $1.0 million ($2.0 million of proceeds, net of the 2015 insurance deductible of $0.5 million and additional expenditures to repair Gregory of $0.5 million) of the proceeds to make a mandatory prepayment on our term loan.

Intangible Assets

Intangible assets of $1.3 million as of September 30, 2018 and December 31, 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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5. LONG-TERM DEBT

Our outstanding debt and related information at September 30, 2018 and December 31, 2017 are as follows (in thousands):

	September 30, 2018			December 31, 2017
Revolving credit facility due 2019	$	83,124		$	94,555
Term loans due 2021	430,204			433,396
Senior unsecured notes payable due 2019	16,334			—
Original issuance discount on term loans due 2021	(893		)	(1,134		)
Total long-term debt (including current portion)	528,769			526,817
Current portion of long-term debt	(522,787		)	(4,256		)
Deferred financing costs	(5,982		)	(8,295		)
Total long-term debt	$	—		$	514,266
Outstanding letters of credit	$	24,861		$	24,911
Remaining unused borrowings	$	12,015		$	15,534

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Weighted average interest rate	7.41		%	6.26		%	7.07		%	6.06		%
Average outstanding borrowings	$	530,208		$	542,578		$	530,208		$	548,529
Maximum borrowings	$	530,227		$	548,080		$	532,952		$	561,305

Senior Credit Facilities

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

Third A&R Revolving Credit Agreement

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

(a) the letters of credit sublimit was set at $75 million; and

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

the Consolidated Interest Coverage Ratio covenants (each as defined in the Third A&R Revolving Credit Agreement, and collectively the “Financial Covenants”) (each such failure, a “Financial Covenant Default”), we have the right (a limited number of times) to cure such Financial Covenant Default by having the Sponsors purchase equity interests in or make capital contributions to us resulting in, among other things, proceeds that, if added to Consolidated EBITDA (as defined in the Third A&R Revolving Credit Agreement) would result in us satisfying the Financial Covenants.

Amendments to Third A&R Revolving Credit Agreement

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

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The First Amendment, among other things:

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

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

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

On 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 $120 million on June 30, 2018 and will be further 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 1.51 to 1.00 as of September 30, 2018;

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

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

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

(viii) beginning with the fiscal quarter ending March 31, 2019, our Consolidated Total Leverage Ratio cannot exceed 5.00 to 1.00 and our Consolidated Senior Secured Leverage Ratio cannot exceed 3.50 to 1.00. Until such time as our Consolidated Total Leverage Ratio is less than 5.00 to 1.00, we will also be restricted from making cash distributions to our unitholders and from entering into acquisition or merger agreements with third-party businesses involving a purchase price greater than $10 million, unless such acquisition is funded entirely using the proceeds from the issuance of equity. In addition, until such time as our Consolidated Total Leverage Ratio is less than or equal to 5.00 to 1.00, we will be required to repay any outstanding borrowings under the Credit Facility in an amount equal to 50% of our Excess Cash Flow (as defined in the Fifth Amendment). Our Consolidated Total Leverage Ratio was 8.61 to 1.00 as of September 30, 2018.

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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 is due August 4, 2019) or waivers of the March 31, 2019 requirement to comply with the Consolidated Total Leverage Ratio (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 September 30, 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), $1.064 million, 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 $1.3 million of PIK interest as of September 30, 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 sheets. Changes in deferred financing costs are as follows (in thousands):

	2018			2017
Deferred financing costs, January 1	$	8,295		$	11,474
Capitalization of deferred financing costs	256			66
Amortization of deferred financing costs	(2,569		)	(2,475		)
Deferred financing costs, September 30	$	5,982		$	9,065

6. COMMITMENTS AND CONTINGENCIES

Legal Matters

From time to time, we are party to certain legal or administrative proceedings that arise in the ordinary course and are incidental to our business. For example, during periods when we are expanding our operations through the development of new pipelines or the construction of new plants, we may become involved in disputes with landowners that are in close proximity to our activities. While we are involved currently in several such proceedings and disputes, our management believes that none of such proceedings or disputes will have a material adverse effect on our results of operations, cash flows or financial condition. However, future events or circumstances, currently unknown to management, will determine whether the resolution of any litigation or claims ultimately will have a material effect on our results of operations, cash flows or financial condition in any future reporting periods.

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TPL. On April 5, 2017, TPL SouthTex Processing Company, LP (“TPL”), an indirect subsidiary of Targa Resources Corp. (“Targa”), filed a Demand for Arbitration with the American Arbitration Association, against FL Rich Gas Services, LP, an indirect subsidiary of the Partnership (“FL Rich”), related to the operation of T2 EF Cogeneration Holdings LLC (“T2 Cogen”). T2 Cogen, the owner of a cogeneration facility in South Texas, is operated by FL Rich pursuant to the terms of the Generation Plant Operating Agreement, dated March 4, 2013 (the “Operating Agreement”). TPL alleges that FL Rich (i) breached the Operating Agreement in its alleged failure to receive from the United States Environmental Protection Agency a Prevention of Significant Deterioration permit thereby harming Targa’s investment in T2 Cogen, (ii) breached its fiduciary duties with respect to funds or assets of T2 Cogen as operator of T2 Cogen under the terms of the Operating Agreement, and (iii) breached the Operating Agreement and the Limited Liability Company Agreement of T2 Cogen (the “LLC Agreement”) in installing a third turbine inside its Lone Star plant. TPL is seeking, among other things, (a) unspecified damages related to the alleged breaches under the Operating Agreement and the LLC Agreement, (b) the return of approximately $26 million in capital contributions to T2 Cogen received from TPL under the LLC Agreement and the Operating Agreement, and (c) the dissolution and liquidation of T2 Cogen and its assets, respectively. An arbitration hearing has been scheduled for January 2019. We believe this matter is without merit and we intend to defend the arbitration vigorously. Because this matter is still in discovery stage, we are unable to predict its outcome and the possible loss or range of loss, if any, associated with its resolution or any potential effect the matter may have on our financial position. Depending on the outcome or resolution of this matter, it could have a material effect on our financial position.

Woodsboro. Our General Partner has been named as a defendant in a lawsuit filed on April 29, 2016 in Duval County, Texas styled Victor Henneke, Jr., et al. v. Southcross Energy Partners GP, LLC, et al., Cause No. DC-16-139, 229th Judicial District, Duval County, Texas (the “Henneke Case”). The Henneke Case involves claims by two employees of a third-party contractor for personal injury and wrongful death resulting from the alleged negligence of the Partnership related to a pipeline construction project located at our Woodsboro processing facility. The Partnership’s insurance carriers are providing coverage to the Partnership under its general liability policy. No trial date has been set for the contractual liability claims in the case. A jury trial for the personal injury claims began in Duval County, Texas on September 18, 2017. On September 22, 2017, two different award amounts were determined by the jury, the first of which was determined prior to the jury being released by the judge and the second was determined after the jury was recalled by the judge. On April 25, 2018, the successor judge entered a judgment against Southcross in the amount of approximately $7.7 million. We have filed an appeal of this judgment and believe that we have adequate insurance coverage to cover this matter. As a result, during the nine months ended September 30, 2018, we recorded a $7.7 million liability and receivable from our insurance carrier related to the Woodsboro legal settlement. On April 27, 2018 and April 30, 2018, the plaintiffs filed two new lawsuits against Southcross CCNG Transmission Ltd. that allege the same or similar causes of actions for which we previouslyreceived judgements 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.

Corpus Christi Alumina LLC v. Southcross Marketing Co. Ltd. (In re Sherwin Alumina Co., LLC), Case No. 18-02024 (Bankr. S.D. Tex.) Corpus Christi Alumina LLC, the assignee of Sherwin Alumina Company LLC, sought to recover from our subsidiary, Southcross Marketing Co. Ltd., natural gas payments made to us prior to Sherwin’s 2016 bankruptcy. We settled this claim for $0.3 million in July 2018.

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. 

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Leases

Capital Leases

We have vehicle leases that are classified as capital leases. The termination dates of the lease agreements vary from 2018 to 2019. We recorded amortization expense related to the capital leases of $0.1 million and $0.4 million for the three and nine months ended September 30, 2018, respectively, and $0.1 million and $0.4 million for the three and nine months ended September 30, 2017, respectively. Capital leases entered into during the three and nine months ended September 30, 2018, were $0.2 million and $1.5 million, respectively. There were no capital leases entered into during the three months ended September 30, 2017. Capital leases entered into during the nine months ended September 30, 2017 were $0.5 million. The capital lease obligation amounts included in the balance sheets were as follows (in thousands):

	September 30, 2018		December 31, 2017
Other current liabilities	$	636	$	410
Other non-current liabilities	1,139		410
Total	$	1,775	$	820

Operating Leases

We maintain operating leases in the ordinary course of our business activities. These leases include those for office and other operating facilities and equipment. The termination dates of the lease agreements vary from 2018 to 2025. Expenses associated with operating leases, recorded in operations and maintenance expenses and general and administrative expenses in our statements of operations, were $1.4 million and $4.2 million for the three and nine months ended September 30, 2018, respectively, and $1.4 million and $4.4 million for the three and nine months ended September 30, 2017, respectively. A rental reimbursement included in our lease agreement associated with the office space we leased in June 2015 of $1.9 million, net of amortization, has been recorded as a deferred liability in our condensed consolidated balance sheets as of September 30, 2018. This amount will continue to be amortized against the lease payments over the length of the lease term.

7. PARTNERS’ CAPITAL

Ownership

Our units outstanding as of September 30, 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, 2017	22,122,113	26,492,074	18,335,181	12,213,713	1,615,573
Vesting of LTIP units, net	44,010	—	—	—	—
In-kind distributions and issuances to general partner to maintain 2.0% ownership	—	—	979,616	—	20,890
Board of director grants	12,739	—	—	—	260
Units outstanding as of September 30, 2018	22,178,862	26,492,074	19,314,797	12,213,713	1,636,723

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 September 30, 2018, the Class B Convertible Units consist of 19,314,797 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.

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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 September 30, 2018, all of our outstanding Class B Convertible Units were indirectly owned by Holdings.

Distribution Rights: The holders of the Class B Convertible Units 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.

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 5.

General Partner Interests

As defined by our Partnership Agreement, general partner units are not considered to be units (common or subordinated), but are representative of our General Partner’s 2.0% ownership interest in us. Our General Partner has received general partner unit PIK distributions in connection with the Class B Convertible Units. In connection with other equity issuances, our General Partner has made capital contributions in exchange for additional general partner units to maintain its 2.0% ownership interest in us.

8. TRANSACTIONS WITH RELATED PARTIES

Affiliated Directors

The SXE 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 the Lenders (one of which must be independent) and one director by majority. Our non-employee directors are reimbursed for certain expenses incurred for their services to us. The director services fees and expenses are included in general and administrative expenses in our statements of operations. We incurred fees and expenses related to the services from our affiliated directors as follows (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
EIG	36		35		108		105
Tailwater	38		36		114		108
Total fees and expenses paid for director services to affiliated entities	$	74	$	71	$	222	$	213

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Southcross Energy Partners GP, LLC (our General Partner)

Our General Partner does not receive a management fee or other compensation for its management of us. However, our General Partner and its affiliates are entitled to reimbursements for all expenses incurred on our behalf, including, among other items, compensation expense for all employees required to manage and operate our business. We incurred expenses related to these reimbursements as follows (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Reimbursements included in general and administrative expenses	$	2,356	$	2,189	$	5,585	$	9,217
Reimbursements included in operations and maintenance expenses	3,896		3,728		10,893		12,546
Total reimbursements to our General Partner and its affiliates	$	6,252	$	5,917	$	16,478	$	21,763

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. We had purchases of NGLs from Holdings of $0.8 million and $1.6 million for the three and nine months ended September 30, 2018 and $0.1 million and $1.4 million for the three and nine months ended September 30, 2017, respectively.

We recorded revenues from affiliates of $75.4 million and $187.3 million for the three and nine months ended September 30, 2018 and $48.4 million and $129.5 million for the three and nine months ended September 30, 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 $48.5 million and $33.2 million as of September 30, 2018 and December 31, 2017, respectively, and accounts payable due to affiliates of $0.1 million and $0.4 million as of September 30, 2018 and December 31, 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 11). The receivable balance due from Holdings is current as of September 30, 2018.

In connection with the execution of the Fifth Amendment, on December 29, 2016, the Partnership entered into (i) the Investment Agreement with Holdings and Wells Fargo Bank, N.A., (ii) the Backstop Agreement with Holdings, Wells Fargo Bank, N.A. and the Sponsors and (iii) the Equity Cure Contribution Amendment with Holdings. See Notes 1 and 5 for additional details.

In connection with the Merger Agreement and Contribution Agreement, Holdings and the Partnership entered into the Letter Agreement (see Note 5 for a description of the Letter Agreement). On July 29, 2018, Holdings terminated the Contribution Agreement as a result of the transactions contemplated thereby not being 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 Robstown, as well as a 57-mile pipeline that enables the Robstown facility to receive natural gas liquids from various pipelines that allow the delivery of fractionated products to several Corpus Christi-area markets. Under the terms of the agreement, EPIC would assume all of the NGL purchase and sale agreements associated with the Robstown fractionator, including those with the Partnership. Since these agreements are expected to remain in place, we do not expect this transaction to have a material effect on the Partnership’s ongoing financial position.

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9. 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, 2017	98,096		$	10.95
Forfeited units	(4,468	)	$	13.63
Units recaptured for tax withholdings(1)	(17,116	)	$	9.83
Vested units(1)	(44,010	)	$	5.00
Unvested - September 30, 2018	32,502		$	7.94

(1) The weighted-average fair-value price on the date of vesting for our vested units was $1.55 and $1.67 for the three and nine months ended September 30, 2018. The weighted-average fair-value price on the date of vesting for our units recaptured for tax withholdings was $1.55 and $1.69 for the three and nine months ended September 30, 2018.

For the nine months ended September 30, 2018, we granted awards under the LTIP with a grant date fair-value of $0.1 million which immediately vested on the grant date. As of September 30, 2018, we had total unamortized compensation expense of $0.1 million related to unvested awards. Compensation expense associated with awards is expected to be recognized over the three-year vesting period from each equity award’s grant date. As of September 30, 2018, we had 5,338,849 units 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 expenses in our statements of operations (in thousands): 

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Unit-based compensation	$	40	$	827	$	210	$	1,241

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 each 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): 

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Matching contributions expensed for employee savings plan	$	145	$	164	$	468	$	555

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

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

		Three Months Ended September 30,				Nine Months Ended September 30,
	Contract Type	2018		2017		2018		2017
Sales of natural gas(1)	Fixed Spread	$	72,221	$	105,503	$	240,096	$	288,381
Sales of NGLs and condensate(1)	Fixed Spread	70,444		40,466		170,528		124,786
Transportation, gathering and processing	Fixed Fee	7,780		7,730		24,041		24,487
Producer fees(2)	Fixed Fee	—		11,324		—		42,227
Treating and compression	Fixed Fee	3,416		3,524		11,011		11,200
Other	N/A	943		1,931		3,178		2,833
Total revenues		$	154,804	$	170,478	$	448,854	$	493,914

(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 $13.0 million and $38.5 million for the three and nine months ended September 30, 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.

11. INVESTMENTS IN JOINT VENTURES

We own equity interests in three joint ventures with Targa as our joint venture partner. T2 Eagle Ford Gathering Company LLC (“T2 Eagle Ford”), T2 LaSalle Gathering Company LLC (“T2 LaSalle”) and T2 Cogen operate pipelines and a cogeneration facility located in South Texas. We indirectly own a 50% interest in T2 Eagle Ford, a 50% interest in T2 Cogen and a 25% interest in T2 LaSalle. We pay our proportionate share of the joint ventures’ operating costs, excluding depreciation and amortization, through lease capacity payments. As a result, our share of the joint ventures’ losses is related primarily to the joint ventures’ depreciation and amortization. Our maximum exposure to loss related to these joint ventures includes our equity investment, any additional capital contributions and our share of any operating expenses incurred by the joint ventures.

The joint ventures’ summarized financial data from their statements of operations for the three and nine months ended September 30, 2018 and 2017 is as follows (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Revenue
T2 Eagle Ford	$	975		$	854		$	2,990		$	3,157
T2 Cogen	84			118			387			233
T2 LaSalle	392			436			1,223			1,220
Net loss
T2 Eagle Ford	$	(4,670	)	$	(4,904	)	$	(14,010	)	$	(14,714	)
T2 Cogen	(910		)	(797		)	(2,666		)	(2,813		)
T2 LaSalle	(1,482		)	(1,468		)	(4,444		)	(4,404		)

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Our equity in losses of joint venture investments is comprised of the following for the three and nine months ended September 30, 2018 and 2017 (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
T2 Eagle Ford	$	(2,335	)	$	(2,452	)	$	(7,005	)	$	(7,357	)
T2 Cogen	(455		)	(399		)	(1,333		)	(1,407		)
T2 LaSalle	(371		)	(367		)	(1,111		)	(1,101		)
Equity in losses of joint venture investments	$	(3,161	)	$	(3,218	)	$	(9,449	)	$	(9,865	)

Our investments in joint ventures is comprised of the following as of September 30, 2018 and December 31, 2017 (in thousands):

	September 30, 2018		December 31, 2017
T2 Eagle Ford	$	85,598	$	92,248
T2 Cogen	3,091		4,425
T2 LaSalle	13,963		15,074
Investments in joint ventures	$	102,652	$	111,747

12. 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 three and nine months ended September 30, 2018 and 2017 represent the following percentages of consolidated revenue: 

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Top ten customers	42.6	%	53.0	%	42.7	%	50.2	%

The percentage of total consolidated revenue for each customer, excluding affiliates, that exceeded 10% of total revenues for the three and nine months ended September 30, 2018 and 2017 was as follows: 

	Three Months Ended September 30,			Nine Months Ended September 30,
	2018	2017		2018	2017
Talen Energy Marketing, LLC	(a)	13.7	%	(a)	(a)
Calpine Energy Services LP	(a)	10.4	%	(a)	(a)

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

For the nine months ended September 30, 2018 and 2017, we did not experience significant non-payment for services. We had no allowance for uncollectible accounts receivable at September 30, 2018.

13. SUBSEQUENT EVENTS

On October 4, 2018, 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 Robstown, as well as a 57-mile pipeline that enables the Robstown facility to receive natural gas liquids from various pipelines that allow the delivery of fractionated products to several Corpus Christi-area markets. See Note 8.

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14. SUPPLEMENTAL INFORMATION

Supplemental Cash Flow Information (in thousands)

	Nine Months Ended September 30,
	2018		2017
Supplemental Disclosures:
Cash paid for interest	$	28,365	$	26,428
Cash paid for taxes	—		4
Supplemental disclosures of non-cash investing and financing activities:
Accounts payable related to capital expenditures	652		1,441
Capital lease obligations	380		53
Class B Convertible unit in-kind distributions	1,075		2,447

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):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Total interest costs	$	11,257		$	10,045		$	32,543		$	29,110
Capitalized interest included in property, plant and equipment, net	(99		)	(114		)	(280		)	(440		)
Interest expense	$	11,158		$	9,931		$	32,263		$	28,670

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 agreements 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 September 30, 2018 were as follows: $0.5 million for the remainder of 2018; $2.2 million in 2019; $2.2 million in 2020; $1.5 million in 2021; $1.5 million in 2022 and $10.2 million thereafter. The revenue for the demand payments is recognized on a straight-line basis over the term of the contract. The demand fee revenues under the contracts were each $0.7 million and $2.0 million for the three and nine months ended September 30, 2018 and 2017, respectively, and have been included within transportation, gathering and processing fees within Note 10. 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 10 were $0.7 million and $1.3 million for the three and nine months ended September 30, 2018, and $0.8 million and $2.3 million for the for the three and nine months ended September 30. 2017, respectively. Deferred revenue associated with these agreements was $11.2 million and $11.6 million at September 30, 2018 and December 31, 2017, respectively.  

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Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.

FORWARD-LOOKING INFORMATION

Investors are cautioned that certain statements contained in this Quarterly Report on Form 10-Q (“Form 10-Q”) as well as in periodic press releases and oral statements made by our management team during our presentations are “forward-looking” statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will continue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would” and “could.” In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us or our subsidiaries, are also forward-looking statements. These forward-looking statements involve external risks and uncertainties, including, but not limited to, those described under the section entitled “Risk Factors” included in our 2017 Annual Report on Form 10-K.

Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond the control of our management team. All forward-looking statements in this Form 10-Q and subsequent written and oral forward-looking statements attributable to us, or to persons acting on our behalf, are expressly qualified in their entirety by these risks and uncertainties. These risks and uncertainties include, among others:

• the volatility of natural gas, crude oil and NGL prices and the price and demand of products derived from these commodities, particularly in the depressed energy price environment that began in the second half of 2014, which has the potential for further deterioration and may result in a continued reduction in exploration, development and production of crude oil and natural gas;

• competitive conditions in our industry and the extent and success of producers increasing production or replacing declining production and our success in obtaining new sources of supply;

• industry conditions and supply of pipelines, processing and fractionation capacity relative to available natural gas from producers;

• our dependence upon a relatively limited number of customers for a significant portion of our revenues;

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

• the financial condition and creditworthiness of our customers;

• our ability to recover NGLs effectively at a rate equal to or greater than our contracted rates with customers;

• our ability to produce and market NGLs at the anticipated differential to NGL index pricing;

• our access to markets enabling us to match pricing indices for purchases and sales of natural gas and NGLs;

• our ability to complete projects within budget and on schedule, including but not limited to, timely receipt of necessary government approvals and permits, our ability to control the costs of construction and other factors that may impact projects;

• our ability to consummate acquisitions, successfully integrate the acquired businesses and realize anticipated cost savings and other synergies from any acquisitions;

• our ability to manage, over time, changing exposure to commodity price risk;

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

• our access to financing and ability to remain in compliance with our financial covenants, and the potential for lack of access to debt and equity capital markets as a result of the depressed energy price environment;

• our ability to generate sufficient operating cash flow to resume funding our quarterly distributions;

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

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

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

• the effects of laws and governmental regulations and policies;

• the effects of existing and future litigation;

• the effects of the termination of the Merger Agreement;

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

• changes in general economic conditions; and

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

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

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

Overview

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

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”), as a result of the merger contemplated by the Merger Agreement not being 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”), as result of the transactions contemplated by the Contribution Agreement not being 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.

Letter Agreement. In connection with the Merger Agreement and Contribution Agreement, Holdings and the Partnership entered into a Letter Agreement (the “Letter Agreement”) providing for Holdings to reimburse the Partnership for all fees or expenses of the Partnership in connection with the Merger Agreement including (i) any fees or expenses of counsel, accountants, investment bankers and consultants retained by the Partnership or the conflicts committee of the Partnership, and (ii) the payment of any termination fee or the reimbursement of any AMID expense, in each case, if the Merger has not closed and (a) the Merger Agreement is terminated because the Contribution Agreement has been terminated under certain specified circumstances, including if the Contribution Agreement is terminated in a manner that results in Holdings being entitled to receive the termination fee, or (b) the Merger Agreement is terminated without the prior approval of the conflicts committee of the Partnership under certain specified circumstances. A portion of the termination fee referenced above was used to reimburse the Partnership’s transaction costs.

Liquidity Consideration

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

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Additionally, pursuant to the Fifth Amendment, (i) total aggregate commitments under the Third A&R Revolving Credit Agreement were reduced from $200 million to $120 million (then further reduced to $115 million on December 31, 2018) and the sublimit for letters of credit also was reduced from $75 million to $50 million (total aggregate commitments will be periodically further reduced through December 31, 2018 to $115 million); (ii) the Consolidated Total Leverage Ratio and Consolidated Senior Secured Leverage Ratio (each as defined in the Fifth Amendment) financial covenants were suspended until the quarter ended March 31, 2019; and (iii) the Consolidated Interest Coverage Ratio (as defined in the Fifth Amendment) financial covenant requirement was reduced from 2.50 to 1.00 to 1.50 to 1.00 for all periods ending on or prior to December 31, 2018 (the “Ratio Compliance Date”). Prior to the Ratio Compliance Date, we will be required to maintain minimum levels of Consolidated EBITDA (as defined in the Fifth Amendment) on a quarterly basis and be subject to certain covenants and restrictions related to liquidity and capital expenditures. See Note 5 to our condensed consolidated financial statements.

In connection with the execution of the Fifth Amendment, on December 29, 2016, the Partnership entered into (i) an Investment Agreement (the "Investment Agreement") with Holdings and Wells Fargo Bank, N.A., (ii) a Backstop Agreement (the "Backstop Agreement") with Holdings, Wells Fargo Bank, N.A. and the Sponsors and (iii) a First Amendment to the equity cure contribution agreement (the "Equity Cure Contribution Amendment") with Holdings. Pursuant to the Equity Cure Contribution Amendment, on December 29, 2016, Holdings contributed $17.0 million to us in exchange for 11,486,486 common units. The proceeds of the $17.0 million contribution were used to pay down the outstanding balance under the Third A&R Revolving Credit Agreement and for general corporate purposes. On January 2, 2018, we notified Holdings that a Full Investment Trigger (as defined in the Investment Agreement) occurred on December 31, 2017. Pursuant to the Backstop Agreement, on January 2, 2018, Holdings delivered a Backstop Demand (as defined in the Investment Agreement) for each Sponsor to fund their respective pro rata portions of the Sponsor Shortfall Amount (as defined in the Investment Agreemen

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

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 5 to our condensed consolidated financial statements.

Distribution Suspension

The board of directors of our General Partner (the “SXE GP Board”) suspended paying a quarterly distribution with respect to the fourth quarter of 2015, every quarter of 2016 and 2017 and the first, second and third quarters of 2018 to conserve any excess cash for the operation of our business. The SXE GP Board and our management believe this suspension to be in the best interest of our unitholders and will continue to evaluate our ability to reinstate the distribution in future periods. More importantly, we are restricted under the terms of the Fifth Amendment from paying a distribution until our Consolidated Total Leverage Ratio is below 5.0. See Notes 1 and 2 to our condensed consolidated financial statements.

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

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

How We Evaluate Our Operations

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

Volume — We determine and analyze volumes by operating unit, but report overall volumes after elimination of intercompany deliveries. The volume of natural gas and NGLs on our systems depends on the level of production from natural gas wells connected to our systems and also from wells connected with other pipeline systems that are interconnected with our systems.

Operations and Maintenance Expense — Our management seeks to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating and maintaining our assets. Direct labor costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operations and maintenance expense. These expenses are relatively stable and largely independent of volumes delivered through our systems, but may fluctuate depending on the activities performed during a specific period.

Adjusted EBITDA and Distributable Cash Flow — We believe that Adjusted EBITDA and distributable cash flow are widely accepted financial indicators of our liquidity and our ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA and distributable cash flow are not measures calculated in accordance with GAAP.

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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 these 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.

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 reconciliations of net cash provided by operating activities to net loss, Adjusted EBITDA and distributable cash flow (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Net cash provided by operating activities	$	546		$	14,552		$	3,339		$	25,836
Add (deduct):
Depreciation and amortization	(17,787		)	(17,521		)	(53,549		)	(53,673		)
Unit-based compensation	(40		)	(827		)	(210		)	(1,241		)
Amortization of deferred financing costs, original issuance discount and PIK interest	(1,373		)	(889		)	(4,143		)	(2,719		)
Gain (loss) on sale of assets, net	84			(186		)	637			5
Unrealized gain (loss) on financial instruments	12			(4		)	13			15
Equity in losses of joint venture investments	(3,161		)	(3,218		)	(9,449		)	(9,865		)
Impairment of assets	—			(1,120		)	—			(1,769		)
Gain on insurance proceeds	—			—			—			1,508
Other, net	63			63			189			411
Changes in operating assets and liabilities:
Trade accounts receivable, including affiliates	10,063			(11,865		)	4,559			(12,503		)
Prepaid expenses and other current assets	49			1,431			7,172			(28		)
Other non-current assets	(101		)	87			(636		)	22
Accounts payable and accrued liabilities, including affiliates	(2,665		)	1,228			7,687			1,912
Other liabilities	(524		)	(789		)	(5,188		)	1,778
Net loss	$	(14,834	)	$	(19,058	)	$	(49,579	)	$	(50,311	)
Add (deduct):
Depreciation and amortization	$	17,787		$	17,521		$	53,549		$	53,673
Interest expense	11,158			9,931			32,263			28,670
Gain on insurance proceeds	—			—			—			(1,508		)
Income tax expense	—			2			—			4
Impairment of assets	—			1,120			—			1,769
Loss (gain) on sale of assets, net	(84		)	186			(637		)	(5		)
Revenue deferral adjustment	(104		)	754			(312		)	2,262
Unit-based compensation	40			827			210			1,241
Major litigation costs, net of recoveries	473			95			1,632			244
Transaction-related costs	122			1,387			940			1,387
Equity in losses of joint venture investments	3,161			3,218			9,449			9,865
Severance expense	331			63			331			2,811
Expenses related to shut-down of Conroe processing plant and conversion of Gregory processing plant	—			681			—			1,288
Other, net	536			36			722			461
Adjusted EBITDA	$	18,586		$	16,763		$	48,568		$	51,851
Cash interest, net of capitalized costs	(9,881		)	(9,182		)	(28,365		)	(26,428		)
Income tax expense	—			(2		)	—			(4		)
Maintenance capital expenditures	(404		)	(1,135		)	(2,155		)	(2,063		)
Distributable cash flow	$	8,301		$	6,444		$	18,048		$	23,356

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Results of Operations

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Revenues:
Revenues	$	79,387		$	122,099		$	261,591		$	364,456
Revenues - affiliates	75,417			48,379			187,263			129,458
Total revenues	154,804			170,478			448,854			493,914
Expenses:
Cost of natural gas and liquids sold	118,377			136,723			346,305			388,362
Operations and maintenance	13,626			14,278			41,975			43,779
Depreciation and amortization	17,787			17,521			53,549			53,673
General and administrative	5,613			6,557			15,529			19,616
Impairment of assets	—			1,120			—			1,769
Loss (gain) on sale of assets, net	(84		)	186			(637		)	(5		)
Total expenses	155,319			176,385			456,721			507,194
Loss from operations	(515		)	(5,907		)	(7,867		)	(13,280		)
Other income (expense):
Equity in losses of joint venture investments	(3,161		)	(3,218		)	(9,449		)	(9,865		)
Interest expense	(11,158		)	(9,931		)	(32,263		)	(28,670		)
Gain on insurance proceeds	—			—			—			1,508
Total other expense	(14,319		)	(13,149		)	(41,712		)	(37,027		)
Loss before income tax expense	(14,834		)	(19,056		)	(49,579		)	(50,307		)
Income tax expense	—			(2		)	—			(4		)
Net loss	$	(14,834	)	$	(19,058	)	$	(49,579	)	$	(50,311	)
Other financial data:
Adjusted EBITDA	$	18,586		$	16,763		$	48,568		$	51,851
Maintenance capital expenditures	$	404		$	1,135		$	2,155		$	2,063
Growth capital expenditures	$	1,671		$	2,956		$	7,539		$	14,964
Operating data:
Average volume of processed gas (MMcf/d)	249			222			239			248
Average volume of NGLs produced (Bbls/d)	31,675			27,840			29,966			30,659
Average daily throughput Mississippi/Alabama (MMcf/d)	155			167			172			167
Realized prices on natural gas volumes ($/Mcf)	$	3.12		$	3.18		$	3.18		$	3.20
Realized prices on NGL volumes ($/gal)	0.69			0.53			0.61			0.52

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Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017

Volume and overview.  Processed gas volumes increased 27 MMcf/d, or 12%, to 249 MMcf/d during the three months ended September 30, 2018, compared to 222 MMcf/d during the three months ended September 30, 2017. This increase in processed gas volumes is due primarily to higher volumes from producers during the three months ended September 30, 2018, as well as the temporary shut-down of our processing plants as a result of Hurricane Harvey during the three months ended September 30, 2017.

NGLs produced at our processing plants for the three months ended September 30, 2018 averaged 31,675 Bbls/d, an increase of 14%, or 3,835 Bbls/d, compared to 27,840 Bbls/d for the three months ended September 30, 2017. The increase in NGLs produced is due primarily to the impact of Hurricane Harvey during the three months ended September 30, 2017.

Revenues.  Our total revenues for the three months ended September 30, 2018 decreased $15.7 million, or 9%, to $154.8 million from $170.5 million for the three months ended September 30, 2017. This decrease was due primarily to a decrease in realized prices in natural gas, partially offset by an increase in NGLs produced for the three months ended September 30, 2018 compared to the three months ended September 30, 2017. In addition, the decrease is due to the reclassification of producer fees as reductions to the costs of natural gas and liquids sold under ASC 606. See Note 10 to our condensed consolidated financial statements.

Cost of natural gas and NGLs sold.  Our cost of natural gas and NGLs sold for the three months ended September 30, 2018 was $118.4 million, compared to $136.7 million for the three months ended September 30, 2017. This decrease of $18.3 million, or 13%, was due primarily to lower natural gas prices compared to the same period in 2017. In addition, the decrease is due to the reclassification of producer fees as reductions to the costs of natural gas and liquids sold line item under ASC 606.

Operations and maintenance expenses. Operations and maintenance expenses for the three months ended September 30, 2018 were $13.6 million, compared to $14.3 million for the three months ended September 30, 2017 for a decrease of $0.7 million, or 5%. This decrease was due primarily to improved operating efficiencies at our facilities.

General and administrative expenses.  General and administrative expenses for the three months ended September 30, 2018 were $5.6 million, compared to $6.6 million for the three months ended September 30, 2017. This decrease of $1.0 million, or 15%, is due primarily to lower employee related expenses of $0.5 million during the three months ended September 30, 2018.

Depreciation and amortization expenses.  Depreciation and amortization expense for the three months ended September 30, 2018 was $17.8 million, compared to $17.5 million for the three months ended September 30, 2017.

Equity in losses of joint venture investments.  Our share of losses incurred by joint venture investments was $3.2 million for both the three months ended September 30, 2018 and September 30, 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 three months ended September 30, 2018, interest expense was $11.2 million, compared to $9.9 million for the three months ended September 30, 2017. This increase of $1.3 million was due primarily to higher interest rates on borrowings and PIK interest paid to Holdings.

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

Volume and overview.  Processed gas volumes decreased 9 MMcf/d, or 4%, to 239 MMcf/d during the nine months ended September 30, 2018, compared to 248 MMcf/d during the nine months ended September 30, 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 three months ended September 30, 2017.

NGLs produced at our processing plants for the nine months ended September 30, 2018 averaged 29,966 Bbls/d, a decrease of 2%, or 693 Bbls/d, compared to 30,659 Bbls/d for the nine months ended September 30, 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.

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Revenues.  Our total revenues for the nine months ended September 30, 2018 decreased $45.0 million, or 9%, to $448.9 million from $493.9 million for the nine months ended September 30, 2017. This decrease was due primarily to a decrease in realized prices in natural gas, as well as a reduction in processed gas volumes compared to the same period in 2017. In addition, the decrease is due to the reclassification of producer fees as reductions to the costs of natural gas and liquids sold line item under ASC 606.

Cost of natural gas and NGLs sold.  Our cost of natural gas and NGLs sold for the nine months ended September 30, 2018 was $346.3 million, compared to $388.4 million for the nine months ended September 30, 2017. This decrease of $42.1 million, or 11%, was due primarily to lower processed gas volumes and lower natural gas prices compared to the same period in 2017. In addition, the decrease is due to the reclassification of producer fees as reductions to the costs of natural gas and liquids sold line item under ASC 606.

Operations and maintenance expenses. Operations and maintenance expenses for the nine months ended September 30, 2018 were $42.0 million, compared to $43.8 million for the nine months ended September 30, 2017 for a decrease of $1.8 million, or 4%. 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 nine months ended September 30, 2018 were $15.5 million, compared to $19.6 million for the nine months ended September 30, 2017. This decrease of $4.1 million, or 21%, is due primarily to severance expense of $2.8 million during the nine months ended September 30, 2017 and $4.4 million of lower employee related expenses, partially offset by transaction-related expenses of $0.9 million during the nine months ended September 30, 2018.

Depreciation and amortization expenses.  Depreciation and amortization expense for the nine months ended September 30, 2018 was $53.5 million, compared to $53.7 million for the nine months ended September 30, 2017.

Equity in losses of joint venture investments.  Our share of losses incurred by joint venture investments was $9.4 million for the nine months ended September 30, 2018 and $9.9 million for the nine months ended September 30, 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 nine months ended September 30, 2018, interest expense was $32.3 million, compared to $28.7 million for the nine months ended September 30, 2017. This increase of $3.6 million was due primarily to higher interest rates on borrowings and PIK interest paid to Holdings.

Liquidity and Capital Resources

Sources of Liquidity

Our primary sources of liquidity are cash generated from operations, cash raised through issuances of additional debt securities and borrowings under our Senior Credit Facilities (as defined in Note 5 to our condensed 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.

We expect to fund short-term cash requirements, such as operating and maintenance and general and administrative expenses and maintenance capital expenditures, primarily through operating cash flows. We expect to fund long-term cash requirements through several sources, including operating cash flows and borrowings under our Senior Credit Facilities. See Notes 1 and 5 to our condensed consolidated financial statements.

Our future cash flow may be materially adversely affected if the natural gas and NGL volumes connected to our systems decline. See Note 1 to our condensed consolidated financial statements. The majority of our revenue is derived from fixed-fee and fixed-spread contracts, which have limited direct exposure to commodity price levels since we are paid based on the volumes of natural gas that we gather, process, treat, compress and transport and the volumes of NGLs we fractionate and transport, rather than being paid based on the value of the underlying natural gas or NGLs. In addition, a portion of our contract portfolio contains minimum volume commitment arrangements. The majority of our volumes are dependent upon the level of producer drilling activity and our success in connecting volumes to our systems. We remain focused on our efforts to improve

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future liquidity, and continue our cost-saving efforts to lower our operating and general and administrative cost structure. Additionally, we intend to capitalize on the improving commercial environment in our key operating areas as we pursue various strategic options to improve our balance sheet.

On December 29, 2016, we entered into the Fifth Amendment, pursuant to which we received a full waiver for all defaults or events of default arising out of our failure to comply with the financial covenant to maintain a Consolidated Total Leverage Ratio less than 5.00 to 1.00 for the quarter ended September 30, 2016. In addition, until such time as our Consolidated Total Leverage Ratio is less than or equal to 5.00 to 1.00, we will be required to repay any outstanding borrowings under the Credit Facility in an amount equal to 50% of our Excess Cash Flow (as defined in the Fifth Amendment). As of September 30, 2018, our Consolidated Total Leverage Ratio was 8.61 to 1.00.

Additionally, pursuant to the Fifth Amendment, (i) the total aggregate commitments under the Third A&R Revolving Credit Agreement were reduced from $200 million to $120 million (then further reduced to $115 million on December 31, 2018) and the sublimit for letters of credit was also reduced from $75 million to $50 million (total aggregate commitments will be periodically reduced further through December 31, 2018); (ii) the Consolidated Total Leverage Ratio and Consolidated Senior Secured Leverage Ratio (each as defined in the Fifth Amendment) financial covenants were suspended until the quarter ended March 31, 2019; and (iii) the Consolidated Interest Coverage Ratio (as defined in the Fifth Amendment) financial covenant requirement was reduced from 2.50 to 1.00 to 1.50 to 1.00 for all periods ending on or prior to December 31, 2018. Prior to the Ratio Compliance Date, we will be required to maintain minimum levels of Consolidated EBITDA on a quarterly basis and be subject to certain covenants and restrictions related to liquidity and capital expenditures. Our Consolidated Interest Coverage Ratio was 1.51 to 1.00 as of September 30, 2018.

On August 10, 2018, we entered into 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, neither of which the Partnership expects, or absent additional amendments to the Third A&R Revolving Credit Agreement (which is due August 4, 2019) or waivers of the March 31, 2019 requirement to comply with the Consolidated Total Leverage Ratio (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 September 30, 2018. See Notes 1 and 5 to our condensed consolidated financial statements.

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

As of November 9, 2018, we had $529.7 million in outstanding borrowings under our Senior Credit Facilities (as defined in Note 5 to our condensed consolidated financial statements) and $15.0 million in Investment Notes, which includes $1.3 million of paid-in-kind (“PIK”) interest. Under our five-year $200 million revolving credit facility due August 2019 (the “Credit Facility”), pursuant to our Third A&R Revolving Credit Agreement, we have the ability to borrow up to $120.0 million less any letters of credit amounts outstanding, which as of November 9, 2018 provided us access to $12.0 million.

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

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

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

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Maintenance capital expenditures	$	404	$	1,135	$	2,155	$	2,063
Growth capital expenditures	1,671		2,956		7,539		14,964
Capital expenditures	$	2,075	$	4,091	$	9,694	$	17,027

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Our growth capital expenditures during the nine months ended September 30, 2018 primarily related to projects to connect new production or 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 nine months ended September 30, 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.

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

Our ability to benefit from growth projects to accommodate producer drilling activity and the associated need for infrastructure assets and services is subject to operational risks and uncertainties such as the uncertainty inherent in some of the assumptions underlying design specifications for new, modified or expanded facilities. These risks also impact third-party service providers and their facilities. Delays or under-performance of our facilities or third-party facilities may adversely affect our ability to generate cash from operations and comply with our obligations, including the covenants under our debt instruments. In other cases, actual production delivered may fall below volume estimates that we relied upon in deciding to pursue an acquisition or other growth project. Future cash flow and our ability to comply with our debt covenants would likewise be affected adversely if we continue to experience declining volumes over a sustained period and/or unfavorable commodity prices.

We continue to face a challenging corporate capital structure with substantial financial leverage and we remain focused on our overall profitability, including managing Partnership-wide, cost-savings initiatives.

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 “SXE GP Board”), together with our management, determined that in our current corporate capital structure and absent continued access to equity cures from our Sponsors or a significant equity infusion from a third party, neither of which the Partnership expects, or absent additional amendments to its Third A&R Revolving Credit Agreement (which is due August 4, 2019) or waivers of the March 31, 2019 requirement to comply with the Consolidated Total Leverage Ratio (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 defined in Note 5). As a result of the Partnership’s expected inability to comply with its financial covenants twelve months from the issuance of this Form 10-Q, together with the maturity date of the Third A&R Revolving Credit Agreement being in less than twelve months, management has determined that there are conditions and events that raise substantial doubt about the Partnership’s ability to continue as a going concern.

If we do not comply with the applicable covenants or if our independent registered public accounting firm reports in a subsequent audit report the existence of substantial doubt regarding our ability to continue as a going concern, then an event of default under the Senior Credit Facilities would occur which would trigger a cross default of Southcross Holdings Borrowers’ credit facilities. Such events of default, if not cured, would allow the lenders under each of these borrowing arrangements to accelerate the maturity of the debt, making it due and payable immediately and for which the Partnership does not have sufficient funds to repay upon an event of default or upon maturity.

Management is pursuing all reasonable options to generate liquidity and maintain compliance with the Partnership’s financial covenants and other commitments including refinancing its indebtedness and negotiating with its lenders for more favorable terms. Management cannot reasonably assure that it will be effective in implementing any such strategy, and consequently, has concluded that substantial doubt exists regarding SXE’s ability to continue as a going concern.

Cash Flows

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

	Nine Months Ended September 30,
	2018			2017
Net cash provided by operating activities	$	3,339		$	25,836
Net cash used in investing activities	(9,362		)	(3,589		)
Net cash provided by (used in) financing activities	3,853			(28,821		)

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Operating cash flows — Net cash provided by operating activities was $3.3 million for the nine months ended September 30, 2018, compared to cash provided by operating activities of $25.8 million for the nine months ended September 30, 2017. The decrease in cash from operating activities of $22.5 million was due primarily to the timing of payments from working capital during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017.

Investing cash flows — Net cash used in investing activities for the nine months ended September 30, 2018 was $9.4 million, compared to net cash used in investing activities of $3.6 million for the nine months ended September 30, 2017. The increase of $5.8 million used in investing activities during nine months ended September 30, 2018 was due primarily to $2.0 million of insurance proceeds from property damage claims, net of expenditures, $3.0 million of proceeds from the sale of assets and $8.9 million received from aid in constructions payments during the nine months ended September 30, 2017, offset by lower capital expenditures of $9.7 million as compared to $17.0 million during the nine months ended September 30, 2017.

Financing cash flows — Net cash provided by financing activities for the nine months ended September 30, 2018 was $3.9 million, compared to net cash used in financing activities of $28.8 million for the nine months ended September 30, 2017. The increase of cash provided by financing activities of $32.7 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 nine months ended September 30, 2018, and lower paydowns of $13.7 million on our Term Loan and Credit Facility during the nine months ended September 30, 2018.

Off-Balance Sheet Arrangements

We have no off-balance sheet financing arrangements.

Recent Accounting Pronouncements

For discussion on specific recent accounting pronouncements affecting us, please see Note 1 to our unaudited condensed consolidated financial statements.

Critical Accounting Policies and Estimates

Our critical accounting policies are consistent with those described in our 2017 Annual Report on Form 10-K.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

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

Item 4.  Controls and Procedures.

Disclosure controls and procedures.  The Chief Executive Officer and Chief Financial Officer of our General Partner, who have responsibility for our management, have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)), as of the end of the period covered by this report (the “Evaluation Date”). Based on such evaluation, the Chief Executive Officer and Chief Financial Officer of our General Partner have concluded that, as of the Evaluation Date, our disclosure controls and procedures are effective.

Internal control over financial reporting.  There were no changes in our system of internal control over financial reporting (as defined in Rule 13a—15(f) or Rule 15d—15(f) of the Exchange Act) during the third quarter of 2018 that have materially affected, or are reasonably likely to affect materially, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1.  Legal Proceedings.

See Note 6 to our condensed consolidated financial statements in Item 1 for information on legal proceedings in which we are involved.

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Item 1A. Risk Factors.

Our Risk Factors are consistent with those disclosed in Part I, Item 1A Risk Factors of our 2017 Annual Report on Form 10-K and the risk factor disclosed under Part II, Item 1A, “Risk Factors” of the June 30, 2018, Quarterly Report on Form 10-Q.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

As discussed in Note 2 to our condensed consolidated financial statements, on August 13, 2018, we issued Class B PIK Units (as defined in Note 2) to the holder of the Class B Convertible Units as a paid-in-kind distribution attributable to the quarter ended June 30, 2018. In connection with the issuance of the Class B PIK Units, our General Partner made a capital contribution in exchange for the issuance of 6,780 general partner units to maintain its 2.0% ownership interest in us.

The general partner units were issued in a private transaction exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as amended. The issuance was not affected using any form of general advertising or general solicitation. Our General Partner represented its intention to acquire the securities for investment purposes only and not with a view to or for sale in connection with any distribution thereof.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

None.

Item 5. Other Information.

None.

Item 6. Exhibits.

The documents in the accompanying Exhibit Index are filed, furnished or incorporated by reference as part of this report and such Exhibit Index is incorporated herein by reference.

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SIGNATURES

Pursuant to the requirements 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:	November 14, 2018	By:	/s/ Bret M. Allan
			Bret M. Allan
			Senior Vice President and Chief Financial Officer
			(Principal Financial Officer and Principal Accounting Officer)

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	EXHIBIT INDEX
Exhibit
Number	Description
10.1#	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).
10.2#	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).
10.3#	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).
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.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 herewith.

** Furnished herewith.

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

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