Edgar Filing: Southcross Energy Partners, L.P.

Document

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, 2017



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

For the transition period from to

Commission File Number: 001-35719

Southcross Energy Partners, L.P.

(Exact name of registrant as specified in its charter)



DELAWARE		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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post 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 (Do not check if a smaller reporting company)		Smaller reporting company x

Emerging Growth Company x

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. x

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 6, 2017, the registrant has 48,614,187 common units outstanding, 12,213,713 subordinated units outstanding and 18,019,811 Class B Convertible Units outstanding. Our common units trade on the NYSE under the symbol “SXE.”

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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, 2017 and December 31, 2016	4

	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2017 and 2016	5

	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2017 and 2016	6

	Condensed Consolidated Statements of Changes in Partners’ Capital for the Nine Months Ended September 30, 2017 and 2016	8

	Notes to Condensed Consolidated Financial Statements (Unaudited)	9

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	38

ITEM 4.	Controls and Procedures	38

PART II — OTHER INFORMATION		38

ITEM 1.	Legal Proceedings	38

ITEM 1A.	Risk Factors	38

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38

ITEM 3.	Defaults Upon Senior Securities	39

ITEM 4.	Mine Safety Disclosures	39

ITEM 5.	Other Information	39

ITEM 6.	Exhibits	39

SIGNATURES		40

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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, 2017		December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	14,652	$	21,226
Trade accounts receivable	30,448		51,894
Accounts receivable - affiliates	18,706		7,976
Prepaid expenses	3,362		2,751
Other current assets	949		4,343
Total current assets	68,117		88,190

Property, plant and equipment, net	928,247		971,286
Investments in joint ventures	114,643		124,096
Other assets	2,499		2,504
Total assets	$	1,113,506	$	1,186,076

LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	47,543	$	50,639
Accounts payable - affiliates	—		524
Current portion of long-term debt	4,256		4,500
Other current liabilities	12,168		10,976
Total current liabilities	63,967		66,639

Long-term debt	518,480		543,872
Other non-current liabilities	14,333		11,936
Total liabilities	596,780		622,447

Commitments and contingencies (Note 6)

Partners' capital:
Common units (48,598,805 and 48,502,090 units outstanding as of September 30, 2017 and December 31, 2016, respectively)	226,031		255,124
Class B Convertible units (18,019,811 and 17,105,875 units issued and outstanding as of September 30, 2017 and December 31, 2016)	269,886		278,508
Subordinated units (12,213,713 units issued and outstanding as of September 30, 2017 and December 31, 2016)	11,066		19,240
General partner interest	9,743		10,757
Total partners' capital	516,726		563,629
Total liabilities and partners' capital	$	1,113,506	$	1,186,076

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,
	2017			2016			2017			2016
Revenues:
Revenues	$	122,099		$	123,043		$	364,456		$	316,673
Revenues - affiliates	48,379			21,619			129,458			72,418
Total revenues (Note 10)	170,478			144,662			493,914			389,091

Expenses:
Cost of natural gas and liquids sold	136,723			108,572			388,362			273,638
Operations and maintenance	14,278			17,781			43,779			54,173
Depreciation and amortization	17,521			31,449			53,673			68,898
General and administrative	6,557			6,831			19,616			22,879
Impairment of assets	1,120			476			1,769			476
Loss (gain) on sale of assets, net	186			(179		)	(5		)	(12,755		)
Total expenses	176,385			164,930			507,194			407,309

Income (loss) from operations	(5,907		)	(20,268		)	(13,280		)	(18,218		)
Other income (expense):
Equity in losses of joint venture investments	(3,218		)	(3,694		)	(9,865		)	(10,656		)
Interest expense	(9,931		)	(8,598		)	(28,670		)	(26,601		)
Gain on insurance proceeds	—			—			1,508			—
Total other expense	(13,149		)	(12,292		)	(37,027		)	(37,257		)
Loss before income tax benefit (expense)	(19,056		)	(32,560		)	(50,307		)	(55,475		)
Income tax benefit (expense)	(2		)	—			(4		)	2
Net loss	$	(19,058	)	$	(32,560	)	$	(50,311	)	$	(55,473	)
General partner unit in-kind distribution	(20		)	(12		)	(50		)	(38		)
Net loss attributable to partners	$	(19,078	)	$	(32,572	)	$	(50,361	)	$	(55,511	)

Earnings per unit
Net loss allocated to limited partner common units	$	(11,545	)	$	(17,915	)	$	(30,590	)	$	(29,235	)
Weighted average number of limited partner common units outstanding	48,574			36,947			48,545			33,119
Basic and diluted loss per common unit	$	(0.24	)	$	(0.48	)	$	(0.63	)	$	(0.88	)

Net loss allocated to limited partner subordinated units	$	(2,902	)	$	(5,920	)	$	(7,694	)	$	(10,777	)
Weighted average number of limited partner subordinated units outstanding	12,214			12,214			12,214			12,214
Basic and diluted loss per subordinated unit	$	(0.24	)	$	(0.48	)	$	(0.63	)	$	(0.88	)

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,
	2017			2016
Cash flows from operating activities:
Net loss	$	(50,311	)	$	(55,473	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization	53,673			68,898
Unit-based compensation	1,241			2,635
Amortization of deferred financing costs, original issuance discount and PIK interest	2,719			2,796
Gain on sale of assets	(5		)	(12,755		)
Unrealized gain on financial instruments	(15		)	(116		)
Equity in losses of joint venture investments	9,865			10,656
Distribution from joint venture investment	—			740
Impairment of assets	1,769			476
Gain on insurance proceeds	(1,508		)	—
Other, net	(411		)	(247		)
Changes in operating assets and liabilities:
Trade accounts receivable, including affiliates	12,503			46,444
Prepaid expenses and other current assets	28			(656		)
Other non-current assets	(22		)	(63		)
Accounts payable and accrued expenses, including affiliates	(1,912		)	(24,685		)
Other liabilities	(1,778		)	2,553
Net cash provided by operating activities	25,836			41,203
Cash flows from investing activities:
Capital expenditures	(17,027		)	(17,329		)
Aid in construction receipts	8,876			—
Insurance proceeds from property damage claims, net of expenditures	2,000			125
Net proceeds from sales of assets	2,974			20,734
Investment contributions to joint venture investments	(412		)	(5,327		)
Net cash used in investing activities	(3,589		)	(1,797		)
Cash flows from financing activities:
Borrowings under our credit facility	—			3,110
Repayments under our credit facility	(24,000		)	(62,250		)
Repayments under our term loan agreement	(4,289		)	(3,375		)
Payments on capital lease obligations	(369		)	(314		)
Financing costs	(44		)	(130		)
Tax withholdings on unit-based compensation vested units	(119		)	(122		)
Borrowing of senior unsecured paid in-kind notes	—			14,000
Repayment of senior unsecured paid in-kind notes and paid in-kind interest	—			(14,260		)
Valley Wells operating expense cap adjustment	—			4,053
Common unit issuances to Holdings for equity contributions	—			12,416
Interest on receivable due from Holdings	—			233
Net cash used in financing activities	(28,821		)	(46,639		)

Net decrease in cash and cash equivalents	(6,574		)	(7,233		)
Cash and cash equivalents — Beginning of period	21,226			11,348
Cash and cash equivalents — End of period	$	14,652		$	4,115

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, 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	$	226,031		$	269,886		$	11,066		$	9,743		$	516,726



	Partners' Capital
	Limited Partners
	Common			Class B Convertible			Subordinated			General Partner			Total
BALANCE - December 31, 2015	$	271,236		$	300,596		$	37,920		$	11,584		$	621,336
Net loss	(29,214		)	(14,380		)	(10,770		)	(1,109		)	(55,473		)
Unit-based compensation on long-term incentive plan	2,635			—			—			—			2,635
Accrued distribution equivalent rights on long-term incentive plan	11			—			—			—			11
Tax withholdings on unit-based compensation vested units	(122		)	—			—			—			(122		)
Interest on receivable due from Holdings	—			—			—			233			233
Common unit issuances to Holdings related to equity cures	12,416			—			—			504			12,920
Valley Wells' operating expense cap adjustment	2,406			—			—			—			2,406
General partner unit in-kind distribution	(21		)	(10		)	(7		)	38			—
Class B Convertible unit in-kind distribution	(1,370		)	1,874			(454		)	(50		)
BALANCE - September 30, 2016	$	257,977		$	288,080		$	26,689		$	11,200		$	583,946

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. Our common units are listed on the New York Stock Exchange under the symbol “SXE.” We are a master limited partnership, headquartered in Dallas, Texas, that provides natural gas gathering, processing, treating, compression and transportation services and NGL fractionation and transportation services. We also source, purchase, transport and sell natural gas and NGLs. Our assets are located in South Texas, Mississippi and Alabama and include two gas processing plants, one fractionation facility, one treating facility and gathering and transportation pipelines.

Southcross Holdings LP, a Delaware limited partnership (“Holdings”), indirectly owns 100% of Southcross Energy Partners GP, LLC, a Delaware limited liability company, our General Partner (“General Partner”) (and therefore controls us), all of our subordinated and Class B convertible units (“Class B Convertible Units”) and 54.5% of our common units. Our General Partner owns an approximate 2.0% interest in us and all of our incentive distribution rights.

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

The AMID Transactions

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

Simultaneously with the execution of the Merger Agreement, on October 31, 2017, AMID and AMID GP entered into a Contribution Agreement (the “Contribution Agreement”) with Holdings. Upon the terms and subject to the conditions set forth in the Contribution Agreement, Holdings will contribute its equity interests in a new wholly owned subsidiary, which will hold substantially all the current subsidiaries (Southcross Holdings Intermediary LLC, a Delaware limited liability company, Southcross Holdings Guarantor GP LLC, a Delaware limited liability company, and Southcross Holdings Guarantor LP, a Delaware limited partnership, which in turn directly or indirectly own 100% of the limited liability company interest of our General Partner and approximately 55% of the Partnership’s common units) and business of Holdings, to AMID and AMID GP in exchange for (i) the number of common units representing limited partner interests in AMID (each an “AMID Common Unit”) equal to $185,697,148, subject to certain adjustments for cash, indebtedness, working capital and transaction expenses contemplated by the Contribution Agreement, divided by $13.69, (ii) 4.5 million new Series E convertible preferred units of AMID (the “AMID Preferred Units”), (iii) options to acquire 4.5 million AMID Common Units (the “Options”), and (iv) 15% of the equity interest in AMID GP (the transactions contemplated thereby and the agreements ancillary thereto, the “Contribution”).

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final resolutions of the Special Indemnity Matters (as defined in the Contribution Agreement). Further, during this time, cash distributions made by AMID or AMID GP to Holdings will be restricted, must remain within Holdings, and will be subject to recapture by AMID. The closing under the Contribution Agreement is conditioned upon, among other things: (i) expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the”HSR Act”), (ii) the absence of certain legal impediments prohibiting the transactions and (iii) with respect to AMID’s obligation to close only, the conditions precedent contained in the Merger Agreement having been satisfied and the Merger having become effective substantially concurrently with the closing of the Contribution Agreement.

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

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

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

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

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

Liquidity Consideration

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

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

Additionally, pursuant to the Fifth Amendment, (i) the total aggregate commitments under the Third A&R Revolving Credit Agreement were reduced from $200 million to $145 million (then further reduced to $140 million on September 30, 2017) 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 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.

In connection with the execution of the Fifth Amendment, on December 29, 2016, the Partnership entered into (i) an Investment Agreement (the "Investment Agreement") with Holdings and Wells Fargo Bank, N.A., (ii) a Backstop Agreement (the "Backstop Agreement") with Holdings, Wells Fargo Bank, N.A. and the Sponsors and (iii) a First Amendment to the equity cure contribution agreement (the "Equity Cure Contribution Amendment") with Holdings. Pursuant to the Equity Cure Contribution Amendment, on December 29, 2016, Holdings contributed $17.0 million to us in exchange for 11,486,486 common units. The proceeds of the $17.0 million contribution were used to pay down the outstanding balance under the Third A&R Revolving Credit Agreement and for general corporate purposes. In addition, pursuant to entering into the Investment Agreement, the previous equity cure contribution agreement with Holdings was terminated and Holdings has agreed to contribute $15.0 million to us (the “Committed Amount”) upon the earlier to occur of December 31, 2017 or notification from the Partnership of an event of default under the Third A&R Revolving Credit Agreement. In exchange for the amounts contributed pursuant to the Investment Agreement upon a Partial Investment Trigger or the Full Investment Trigger (each defined in the Investment Agreement), we will issue to Holdings, at Holdings’ election, either (i) a number of common units at an issue price equal to either (a) if the common units are listed on a national stock exchange, 93% of the volume weighted average price of such common units for the 20-day period immediately preceding the date of the contribution or (b) if the common units are not listed on a national stock exchange, the fair market value of such common units as reasonably agreed by us and Holdings or (ii) a senior unsecured note of the Partnership in an initial face amount equal to the amount of the contribution by Holdings (an “Investment Note”). If Holdings elects to receive an Investment Note in exchange for a contribution pursuant to the Investment Agreement, such Investment Note will mature on or after November 5, 2019 and bear interest at a rate of 12.5% per annum payable in-kind prior to December 31, 2018 and in cash on or after December 31, 2018. The Investment Note, if any, will be our unsecured obligation subordinate in right of payment to any of our secured obligations under the Third A&R Revolving Credit Agreement and will contain covenants and events of default no more restrictive than those currently provided in the Third A&R Revolving Credit Agreement.

Pursuant to the Backstop Agreement, if Holdings is unable to satisfy its obligations under the Investment Agreement with cash on hand upon the occurrence of a Partial Investment Trigger or a Full Investment Trigger, the Sponsors have agreed to fund Holdings’ shortfall in providing the Committed Amount by contributing each Sponsor’s respective pro-rata portion of the shortfall to Holdings or, at the election of each Sponsor, directly to us. As consideration for any amounts contributed directly to us by a Sponsor pursuant to the Backstop Agreement, we will issue to such Sponsor the common units or Investment Note that would have otherwise been issued to Holdings under the Investment Agreement with respect to the amount contributed by the Sponsor. However, under the terms of the Merger Agreement, we are not permitted to issue additional common units without the prior written consent of AMID.

Based upon the Partnership’s financial forecast, the Fifth Amendment, as well as the Committed Amount, we believe management's executed plans provide the Partnership with sufficient liquidity to fund future operations through at least twelve months from the date that these financial statements were issued.

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Basis of Presentation

We prepared this report under the rules and regulations of the Securities and 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 2016 Annual Report on Form 10-K (“2016 Annual Report on Form 10-K”). The condensed consolidated financial statements as of September 30, 2017 and December 31, 2016, and for the three and nine months ended September 30, 2017 and 2016, are unaudited and have been prepared on the same basis as the audited financial statements included in our 2016 Annual Report on Form 10-K. 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.

The disclosures included in this report provide an update to our 2016 Annual Report on Form 10-K.

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.

The condensed consolidated statement of cash flows for the nine months ended September 30, 2016, has been reclassified for consistency with the current period presentation for aid in construction payment receipts. Beginning in the second quarter of 2017, and continuing in the third quarter of 2017, we reclassified payments for aid in construction projects to a separate line item for the six months ended June 30, 2017 and 2016 and the nine months ended September 30, 2017 and 2016. Previously, such payments were included in the capital expenditures line item. Aid in construction projects refer to certain capital projects in which third parties are obligated to reimburse us for all or a portion of the project expenditures.

Segments

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

Significant Accounting Policies

During the nine months ended September 30, 2017, there were no material changes to our significant accounting policies described in Note 1 of our 2016 Annual Report on Form 10-K.

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 2014, the Financial Accounting Standards Board (“FASB”) issued a comprehensive new revenue recognition standard that will supersede substantially all existing revenue recognition guidance under GAAP. The standard's core principle is that a company will recognize revenue when it transfers promised goods or services to customers and in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In April 2016, the FASB issued an accounting pronouncement that updates the identifying performance obligations and licensing implementation guidance. We are currently evaluating our contract mix, developing our implementation plan, and assessing the impact to our existing accounting policies and controls that may be impacted by the standard. We will adopt this Accounting Standards Update as required on January 1, 2018, using the modified retrospective method of adoption.

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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, 2017 and 2016 (in thousands, except unit and per unit data):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Net loss	$	(19,058	)	$	(32,560	)	$	(50,311	)	$	(55,473	)
General partner unit in-kind distribution	(20		)	(12		)	(50		)	(38		)
Net loss attributable to partners	$	(19,078	)	$	(32,572	)	$	(50,361	)	$	(55,511	)

General partner's interest⁽¹⁾	$	(396	)	$	(655	)	$	(1,019	)	$	(1,119	)
Class B Convertible limited partner interest⁽¹⁾	(4,235		)	(8,082		)	(11,058		)	(14,380		)
Limited partners' interest⁽¹⁾
Common	$	(11,545	)	$	(17,915	)	$	(30,590	)	$	(29,235	)
Subordinated	(2,902		)	(5,920		)	(7,694		)	(10,777		)


(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	2017			2016			2017			2016
Interest in net loss	$	(11,545	)	$	(17,915	)	$	(30,590	)	$	(29,235	)
Effect of dilutive units - numerator⁽¹⁾	—			—			—			—
Dilutive interest in net loss	$	(11,545	)	$	(17,915	)	$	(30,590	)	$	(29,235	)

Weighted-average units - basic	48,573,647			36,947,132			48,544,728			33,118,605
Effect of dilutive units - denominator⁽¹⁾	—			—			—			—
Weighted-average units - dilutive	48,573,647			36,947,132			48,544,728			33,118,605

Basic and diluted net loss per common unit	$	(0.24	)	$	(0.48	)	$	(0.63	)	$	(0.88	)

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	Three Months Ended September 30,						Nine Months Ended September 30,
Subordinated Units	2017			2016			2017			2016
Interest in net loss	$	(2,902	)	$	(5,920	)	$	(7,694	)	$	(10,777	)
Effect of dilutive units - numerator ⁽¹⁾	—			—			—			—
Dilutive interest in net loss	$	(2,902	)	$	(5,920	)	$	(7,694	)	$	(10,777	)

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	$	(0.24	)	$	(0.48	)	$	(0.63	)	$	(0.88	)

(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 86,418 and 46,551 unvested awards granted under the LTIP for the three and nine months ended September 30, 2017, respectively. The weighted average units that were not included in the computation of diluted per unit amounts were 55,202 and 17,453 for the three and nine months ended September 30, 2016, respectively.

Our calculation of the number of weighted-average units outstanding includes the common units that have been awarded to our directors that are deferred under our Non-Employee Director Deferred Compensation Plan (the “Plan”). In connection with the execution of the Merger Agreement, the board of directors of our General Partner approved an amendment (the “Amendment”) to the Plan. In connection with and pursuant to the terms of the Merger Agreement, the Partnership is required to terminate the Plan and liquidate the sole participant’s account within 30 days prior to the closing of the Merger. The Amendment terminates the Plan effective as of one business day prior to the closing of the Merger and provides that the participant’s account will be liquidated and paid to the participant or his beneficiary, if applicable, in the form of a lump sum cash payment as soon as practical following the effective time of the Merger. The Amendment will be null and void in the event that the closing of the Merger does not occur.

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. In addition, 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 board of directors of our General Partner suspended paying a quarterly distribution with respect to the fourth quarter of 2015, every quarter of 2016 and the first three quarters of 2017 to conserve any excess cash for the operation of our business. The board of directors of our General Partner and our management believe this suspension to be in the best interest of our unitholders and will continue to evaluate our ability to reinstate the distribution in future periods, subject to the conditions of our credit agreement.

Paid In-Kind Distributions

Class B Convertible Units. As of September 30, 2017, the Class B Convertible Units consisted of 18,019,811 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

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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.

The following table presents the Class B PIK Units distributions issued on the Class B Convertible Units during 2017 (in thousands, except per unit and in-kind distribution units):



Payment Date	Attributable to the Quarter Ended	Per Unit Distribution		In-Kind Class B Convertible Unit Distributions to Class B Convertible Holders	In-Kind Class B Convertible Distributions Value⁽¹⁾		In-Kind Unit Distribution to General Partner	In-Kind General Partner Distribution Value⁽¹⁾
2017
November 11, 2017	September 30, 2017	$	0.3257	315,370	$	741	6,436	$	15
August 11, 2017	June 30, 2017	$	0.3257	309,946	$	983	6,325	$	20
May 11, 2017	March 31, 2017	$	0.3257	304,615	$	1,060	6,216	$	22
2016
February 14, 2017	December 31, 2016	$	0.3257	299,375	$	404	6,109	$	8


(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, 2017, the fair value of our term loan was $375.5 million, based on recent trading levels and is considered a Level 2 fair value instrument.

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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, 2017
$	50,000	3.000	%	December 31, 2015	December 31, 2017	—
50,000		3.000	%	June 30, 2016	June 30, 2018	—
40,000		3.000	%	December 31, 2016	January 1, 2018	—
40,000		3.000	%	December 31, 2016	July 1, 2018	—
40,000		3.000	%	December 31, 2016	January 1, 2019	1
60,000		3.000	%	June 30, 2017	June 30, 2019	3
						$	4

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, 2017 or December 31, 2016.

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, 2017		December 31, 2016
Current interest rate derivative assets	$	2	$	2
Non-current interest rate derivative assets	2		2
Current interest rate derivative (liabilities)	—		(15		)
Total interest rate derivatives	$	4	$	(11	)

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,
	2017		2016			2017			2016
Unrealized loss (gain) on interest rate derivatives	$	5	$	(61	)	$	—		$	(116	)
Realized loss (gain) on interest rate derivatives	—		50			(15		)	248

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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, 2017			December 31, 2016
Pipelines	15-30	$	570,557		$	552,540
Gas processing, treating and other plants	15	513,872			509,840
Compressors	5-15	77,368			72,054
Rights of way and easements	15	49,897			49,998
Furniture, fixtures and equipment	5	9,731			9,269
Capital lease vehicles	3-5	2,094			1,713
Total property, plant and equipment		1,223,519			1,195,414
Accumulated depreciation and amortization		(316,368		)	(262,709		)
Total		907,151			932,705

Construction in progress		7,119			16,150
Land and other		13,977			22,431
Property, plant and equipment, net		$	928,247		$	971,286

Depreciation is provided using the straight-line method based on the estimated useful life of each asset.

As part of Partnership-wide cost-saving initiatives, in December 2016 we shut down our Conroe processing plant (“Conroe”) and converted our Gregory cryogenic processing plant (“Gregory”) into a compressor station. The gas previously processed at Gregory has been re-rerouted to our Woodsboro processing facility beginning in the fourth quarter of 2016. During the nine months ended September 30, 2017, we sold $1.6 million of the assets associated with Conroe and Gregory. In October 2017, we sold the remaining Gregory assets for $0.4 million. As a result, we recorded an impairment of $1.1 million during the three months ended September 30, 2017, to adjust the fair value of these assets to fair value.

In an effort to further our cost-saving initiatives, management elected to idle the Bonnie View fractionation facility (“Bonnie View”) in the second quarter of 2017. As a result, all of our Y-grade product will be sold to Holdings in accordance with our affiliate Y-grade sales agreement and will be fractionated at the Holdings’ Robstown fractionation facility (“Robstown”). We plan to utilize Bonnie View as a backup option to the extent Robstown is unable to fractionate our Y-grade product and, therefore, we plan to spend an immaterial amount of capital during the remainder of 2017 to ensure Bonnie View remains available in the future. Our election to idle Bonnie View has not had a material impact to our third quarter of 2017 earnings and cash flows, and is not expected to have a material impact on our future earnings and cash flows.

In January 2015, we shut down Gregory for four weeks due to a fire at the facility. In December 2016, we reached a settlement related to the Gregory fire with our insurance carriers. We received a payment of $2.0 million from our insurance carriers in the first quarter of 2017 and recorded a $1.5 million gain related to insurance proceeds received in excess of expenditures incurred to repair Gregory. As stipulated in the Term Loan Agreement (defined in Note 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 $1.4 million as of September 30, 2017 and December 31, 2016, respectively, represent the unamortized value assigned 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, 2017 and December 31, 2016 are as follows (in thousands):



	September 30, 2017			December 31, 2016
Revolving credit facility due 2019	$	98,555		$	122,555
Term loans due 2021	434,460			438,749
Original issuance discount on term loans due 2021	(1,214		)	(1,458		)
Total long-term debt (including current portion)	531,801			559,846
Current portion of long-term debt	(4,256		)	(4,500		)
Deferred financing costs	(9,065		)	(11,474		)
Total long-term debt	$	518,480		$	543,872

Outstanding letters of credit	$	24,811		$	19,378
Remaining unused borrowings	$	16,634		$	3,067



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Weighted average interest rate	6.26		%	5.26		%	6.06		%	5.24		%
Average outstanding borrowings	$	542,578		$	571,468		$	548,529		$	601,956
Maximum borrowings	$	548,080		$	571,555		$	561,305		$	628,055

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

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

On December 9, 2016, we entered into the fourth amendment to the Third A&R Revolving Credit Agreement which stipulated, among other things, that (i) the deadline for funding the Q3 2016 Equity Cure was further extended and (ii) that any account into which we deposited funds, securities or commodities will be subject to a lien and control agreement for the benefit of the secured parties under the Third A&R Revolving Credit Agreement.

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

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

(ii) reduced the total aggregate commitments under the Third A&R Revolving Credit Agreement from $200 million to $145 million and reduced the sublimit for letters of credit from $75 million to $50 million. Total aggregate commitments was reduced to $140 million on September 30, 2017, and will be further reduced to $135 million on December 31, 2017, $125 million on March 31, 2018, $120 million on June 30, 2018 and $115 million on December 31, 2018 and will also be reduced in an amount equal to the net proceeds of any Permitted Note Indebtedness (as defined in the Fifth Amendment) we may incur in the future;

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

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

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(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 7.81 to 1.00 as of September 30, 2017.

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.

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):



	2017			2016
Deferred financing costs, January 1	$	11,474		$	14,141
Capitalization of deferred financing costs	66			130
Amortization of deferred financing costs	(2,475		)	(2,290		)
Deferred financing costs, September 30	$	9,065		$	11,981

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.

Formosa. On March 5, 2013, one of our subsidiaries, Southcross Marketing Company Ltd., filed suit in a District Court of Dallas County against Formosa Hydrocarbons Company, Inc. (“Formosa”). The lawsuit sought recoveries of losses that we believe our subsidiary experienced as a result of the failure of Formosa to perform certain obligations under the gas processing and sales contract between the parties. Formosa filed a response generally denying our claims and, later, Formosa filed a counterclaim against our subsidiary claiming our subsidiary breached the gas processing and sales contract and a related agreement between the parties for the supply by Formosa of residue gas to a third party on behalf of our subsidiary. On

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December 5, 2016, we reached a final settlement with Formosa and the appeals have been dismissed. We were awarded $3.1 million, of which we received $1.6 million on December 30, 2016. We recorded a receivable of $1.6 million in our consolidated balance sheet as of December 31, 2016 for the remaining balance, which was received in January 2017.

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. No arbitration hearing has yet been scheduled. We believe this matter is without merit and we intend to defend the arbitration vigorously. Because this matter is in an early stage, we are unable to predict its outcome and the possible loss or range of loss, if any, associated with its resolution or any potential effect the matter may have on our financial position. Depending on the outcome or resolution of this matter, it could have a material effect on our financial position.

Woodsboro. Our General Partner has been named as a defendant in a lawsuit filed April 29, 2016 in Duval County, Texas styled Victor Henneke, Jr., et al. v. Southcross Energy Partners GP, LLC 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. The Judge ultimately elected to not enter either jury verdict and a new trial was ordered by the court on September 29, 2017. The Judge subsequently resigned from the bench on October 2, 2017. A new trial is pending the appointment or replacement of the Judge. We believe that we have adequate insurance to cover this litigation. However, it is not possible to predict the ultimate outcome of this litigation.

Regulatory Compliance

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

Leases

Capital Leases

We have vehicle leases that are classified as capital leases. The termination dates of the lease agreements vary from 2017 to 2019. We recorded amortization expense related to the capital leases of $0.1 million and $0.4 million for the three and nine months ended September 30, 2017, respectively, and $0.1 million and $0.3 million for the three and nine months ended September 30, 2016, 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. Capital leases entered into during the three and nine months ended September 30, 2016 were $0.1 million and $0.4 million, respectively. The capital lease obligation amounts included on the balance sheets were as follows (in thousands):



	September 30, 2017		December 31, 2016
Other current liabilities	$	421	$	396
Other non-current liabilities	444		497
Total	$	865	$	893

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Operating Leases

We maintain operating leases in the ordinary course of our business activities. These leases include those for office and other operating facilities and equipment. The termination dates of the lease agreements vary from 2017 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 $4.4 million for the three and nine months ended September 30, 2017, respectively, and $1.5 million and $4.2 million for the three and nine months ended September 30, 2016, respectively. A rental reimbursement included in our lease agreement associated with the office space we leased in June 2015 of $1.8 million, net of amortization, has been recorded as a deferred liability in our condensed consolidated balance sheets as of September 30, 2017. 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, 2017 are as follows (in units):



	Partners’ Capital
		Owned by Parent
	Public	Holdings	Class B		General
	Common	Common	Convertible	Subordinated	Partner
Units outstanding as of December 31, 2016	22,010,016	26,492,074	17,105,875	12,213,713	1,588,198
Vesting of LTIP units, net	96,715	—	—	—	—
In-kind distributions and issuances to general partner to maintain 2.0% ownership	—	—	913,936	—	20,625
Units outstanding as of September 30, 2017	22,106,731	26,492,074	18,019,811	12,213,713	1,608,823

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, 2017, the Class B Convertible Units consist of 18,019,811 units, inclusive of any Class B PIK Units issued. The Class B Convertible Units have the same rights, preferences and privileges, and are subject to the same duties and obligations, as our common units, with certain exceptions as noted below.

Our Partnership Agreement does not allow additional Class B Convertible Units (other than Class B PIK Units) to be issued without the prior approval of our General Partner and the holders of a majority of the outstanding Class B Convertible Units. As of September 30, 2017, 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.

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Charlesbank Capital Partners, LLC(1)	$	—	$	—	$	—	$	94
EIG	35		14		105		59
Tailwater	36		14		108		58
Total fees and expenses paid for director services to affiliated entities	$	71	$	28	$	213	$	211


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

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Southcross Energy Partners GP, LLC (our General Partner)

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Reimbursements included in general and administrative expenses	$	2,189	$	3,190	$	9,217	$	10,224
Reimbursements included in operations and maintenance expenses	3,728		5,469		12,546		16,315
Total reimbursements to our General Partner and its affiliates	$	5,917	$	8,659	$	21,763	$	26,539

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 $0.1 million and $1.4 million for the three and nine months ended September 30, 2017, respectively.

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

We recorded revenues from affiliates of $48.4 million and $129.5 million for the three and nine months ended September 30, 2017, respectively, and $21.6 million and $72.4 million for the three and nine months ended September 30, 2016, respectively, in accordance with the G&P Agreement, the NGL Agreement and the series of commercial agreements.

We had accounts receivable due from affiliates of $18.7 million and $8.0 million as of September 30, 2017 and December 31, 2016, respectively, and accounts payable due to affiliates of $0.5 million as of December 31, 2016. 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, 2017.

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.

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.

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

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



	Units		Weighted-Average Fair Value at Grant Date
Unvested - December 31, 2016	368,281		$	14.91
Forfeited units	(102,478	)	$	13.99
Units recaptured for tax withholdings⁽¹⁾	(42,966	)	$	15.41
Vested units⁽¹⁾	(96,715	)	$	15.33
Unvested - September 30, 2017	126,122		$	15.04

(1) The weighted-average fair value price on the date of vesting for our vested units was $2.67 for both the three and nine months ended September 30, 2017, respectively. The weighted-average fair value price on the date of vesting for our units recaptured for tax withholdings was $2.65 and $2.64 for the three and nine months ended September 30, 2017, respectively.

For the nine months ended September 30, 2017, we did not grant any equity awards under the LTIP. As of September 30, 2017, we had total unamortized compensation expense of $0.4 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, 2017, we had 5,317,360 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,
	2017		2016		2017		2016
Unit-based compensation	$	827	$	929	$	1,241	$	2,635

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 $16,200 annually for the period. The following table summarizes information regarding contributions and the expense recognized for the matching contributions, which is included in operating and maintenance expense and general and administrative expense on our statements of operations (in thousands):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Matching contributions expensed for employee savings plan	$	164	$	338	$	555	$	946

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10. REVENUES

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Sales of natural gas	$	105,503	$	76,614	$	288,381	$	192,673
Sales of NGLs and condensate	40,466		39,640		124,786		107,662
Transportation, gathering and processing fees	22,578		27,775		77,914		85,067
Other⁽¹⁾	1,931		633		2,833		3,689
Total revenues	$	170,478	$	144,662	$	493,914	$	389,091

(1) Other revenue for the three and nine months ended September 30, 2017 includes $1.1 million of business interruption insurance proceeds related to the outage at Holdings’ Lancaster gas treating facility in February 2016.

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, 2017 and 2016 is as follows (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Revenue
T2 Eagle Ford	$	854		$	1,393		$	3,157		$	4,437
T2 Cogen	118			557			233			2,556
T2 LaSalle	436			456			1,220			1,250

Net loss
T2 Eagle Ford	$	(4,904	)	$	(4,878	)	$	(14,714	)	$	(14,383	)
T2 Cogen	(797		)	(1,767		)	(2,813		)	(4,727		)
T2 LaSalle	(1,468		)	(1,486		)	(4,404		)	(4,405		)

Our equity in losses of joint venture investments is comprised of the following for the three and nine months ended September 30, 2017 and 2016 (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
T2 Eagle Ford	$	(2,452	)	$	(2,439	)	$	(7,357	)	$	(7,192	)
T2 Cogen	(399		)	(883		)	(1,407		)	(2,363		)
T2 LaSalle	(367		)	(372		)	(1,101		)	(1,101		)
Equity in losses of joint venture investments	$	(3,218	)	$	(3,694	)	$	(9,865	)	$	(10,656	)

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Our investments in joint ventures is comprised of the following as of September 30, 2017 and December 31, 2016 (in thousands):



	September 30, 2017		December 31, 2016
T2 Eagle Ford	$	94,582	$	101,669
T2 Cogen	4,668		6,003
T2 LaSalle	15,393		16,424
Investments in joint ventures	$	114,643	$	124,096

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, 2017 and 2016 represent the following percentages of consolidated revenue:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Top ten customers	53.0	%	55.1	%	50.2	%	59.0	%

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, 2017 and 2016 was as follows:



	Three Months Ended September 30,			Nine Months Ended September 30,
	2017		2016	2017	2016
Talen Energy Marketing, LLC	13.7	%	(a)	(a)	(a)
Calpine Energy Services LP	10.4	%	(a)	(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 three and nine months ended September 30, 2017 and 2016, we did not experience significant non-payment for services. We had no allowance for uncollectible accounts receivable at September 30, 2017. We recorded an allowance for uncollectible accounts receivable of $0.1 million at December 31, 2015, which was written off in 2016.

13. SUBSEQUENT EVENTS

See description of the AMID Merger Agreement in Note 1.

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14. SUPPLEMENTAL INFORMATION

Supplemental Cash Flow Information (in thousands)



	Nine Months Ended September 30,
	2017		2016
Supplemental Disclosures:
Cash paid for interest, net of amounts capitalized	$	26,428	$	26,197
Cash paid (received) for taxes	4		(52		)
Supplemental disclosures of non-cash investing and financing activities:
Accounts payable related to capital expenditures	1,441		4,039
Capital lease obligations	53		—
Accrued distribution equivalent rights on LTIP units	—		11
Class B Convertible unit in-kind distributions	2,447		1,874
PIK interest	—		260
Common unit issuances to General Partner related to equity cures	—		504

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,
	2017			2016			2017			2016
Total interest costs	$	10,045		$	8,783		$	29,110		$	27,338
Capitalized interest included in property, plant and equipment, net	(114		)	(185		)	(440		)	(737		)
Interest expense	$	9,931		$	8,598		$	28,670		$	26,601

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, 2017 were as follows: $1.4 million for the remainder of 2017; $2.2 million in 2018; $2.2 million in 2019; $2.2 million in 2020 and $13.1 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 $0.7 million and $2.0 million for the three and nine months ended September 30, 2017 and 2016, 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 $0.8 million and $2.3 million for the three and nine months ended September 30, 2017 and 2016, respectively. Deferred revenue associated with these agreements was $10.8 million and $8.5 million at September 30, 2017 and December 31, 2016, 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 2016 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, including with respect to our acquisition of certain gathering, treating, compression and transportation assets acquired in May 2015;


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


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


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


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


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


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


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


•	the effects of laws and governmental regulations and policies;


•	the effects of existing and future litigation;


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


•	the timing and likelihood of completion of the proposed Merger, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals for the proposed Merger that could reduce anticipated benefits or cause the parties to abandon the proposed transaction;

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


•	the risk that the businesses of the Partnership and AMID will not be integrated successfully;


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


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


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


•	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.

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 Holdings LP, a Delaware limited partnership (“Holdings”), indirectly owns 100% of Southcross Energy Partners GP, LLC, a Delaware limited liability company, our General Partner (“General Partner”) (and therefore controls us), all of our subordinated units and Class B convertible units and 54.5% of our common units. Our General Partner owns a 2.0% interest in us and all of our incentive distribution rights.

Recent Developments

The AMID Transactions

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contemplated by the Contribution Agreement, divided by $13.69, (ii) 4.5 million new Series E convertible preferred units of AMID (the “AMID Preferred Units”), (iii) options to acquire 4.5 million AMID Common Units (the “Options”), and (iv) 15% of the equity interest in AMID GP (the transactions contemplated thereby and the agreements ancillary thereto, the “Contribution”).

The Contribution Agreement contains customary representations and warranties and covenants by each of the parties. Holdings has also undertaken several additional obligations under the Contribution Agreement with respect to the Partnership and our subsidiaries. These include, without limitation, Holdings’ indemnification of AMID for certain obligations with respect to breaches of representations and warranties regarding the Partnership and our subsidiaries. In addition, Holdings is indemnifying AMID for certain contingent liabilities of the Partnership and our subsidiaries, including several ongoing litigation matters. A portion of the consideration, including approximately $25 million of the AMID Common Units to be received by Holdings will be deposited into escrow in order to secure the potential indemnification obligations until the longer of the end of 12 months from the closing of the Contribution Agreement, May 31, 2019 or the final resolution of the Special Indemnity Matters (as defined in the Contribution Agreement). In addition, all of the AMID Common Units, AMID Preferred Units and the Options received by Holdings as consideration under the Contribution Agreement will be subject to a lock-up agreement whereby such securities will be locked up until the longer of 12 months (with respect to the AMID Common Units) and 24 months (with respect to the AMID Preferred Units and Options) and, together with the AMID GP equity interests, the final resolutions of the Special Indemnity Matters (as defined in the Contribution Agreement). Further, during this time, cash distributions made by AMID or AMID GP to Holdings will be restricted, must remain within Holdings, and will be subject to recapture by AMID. The closing under the Contribution Agreement is conditioned upon, among other things: (i) expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”), (ii) the absence of certain legal impediments prohibiting the transactions and (iii) with respect to AMID’s obligation to close only, the conditions precedent contained in the Merger Agreement having been satisfied and the Merger having become effective substantially concurrently with the closing of the Contribution Agreement.

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(ii) the payment of any Termination Fee or the reimbursement of any AMID Expense, in each case if the Merger has not closed and (a) the Merger Agreement is terminated because the Contribution Agreement has been terminated under certain specified circumstances or (b) the Merger Agreement is terminated without the prior approval of the conflicts committees of the Partnership under certain specified circumstances.

Hurricane Harvey

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

Liquidity Consideration

On December 29, 2016, we entered into the fifth amendment to the Third A&R Revolving Credit Agreement (the “Fifth Amendment”), pursuant to which we received a full waiver for all defaults or events of default arising out of our failure to comply with the financial covenant to maintain a Consolidated Total Leverage Ratio less than 5.00 to 1.00 for the quarter ended September 30, 2016. Pursuant to the Fifth Amendment, (i) the total aggregate commitments under the Third A&R Revolving Credit Agreement were reduced from $200 million to $145 million and the sublimit for letters of credit 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 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.

Distribution Suspension

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

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industrial, commercial and power generation customers and local distribution companies. All of our operations are managed as and presented in one reportable segment.

Our results are determined primarily by the volumes of natural gas we gather and process, the efficiency of our processing plants and NGL fractionation plants, the commercial terms of our contractual arrangements, natural gas and NGL prices and our operations and maintenance expense. We manage our business with the goal to maximize the gross operating margin we earn from contracts balanced against any risks we assume in our contracts. Our contracts vary in duration from one month to several years and the pricing under our contracts varies depending upon several factors, including our competitive position, our acceptance of risks associated with longer-term contracts and our desire to recoup over the term of the contract any capital expenditures that we are required to incur to provide service to our customers. We purchase, gather, process, treat, compress, transport and sell natural gas and purchase, fractionate, transport and sell NGLs. Contracts with a counterparty generally contain one or more of the following arrangements:


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

•

Fixed-Spread. Under these arrangements, we purchase natural gas and NGLs from producers or suppliers at receipt points on our systems at an index price plus or minus a fixed price differential and sell these volumes of natural gas and NGLs at delivery points off our systems at the same index price, plus or minus a fixed price differential. By entering into such back-to-back purchases and sales, we are able to mitigate our risk associated with changes in the general commodity price levels of natural gas and NGLs. We remain subject to variations in our fixed-spreads to the extent we are unable to match precisely 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 generally are 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 directly related to the volume of natural gas that flows through our systems and is generally independent from general commodity price levels. A sustained decline in commodity prices could result in a decline in volumes entering our system and, thus, a decrease in gross operating margin for our fixed-fee and fixed-spread arrangements. 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 NGLs 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 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.

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

We define Adjusted EBITDA as net income/loss, plus interest expense, income tax expense, depreciation and amortization expense, equity in losses of joint venture investments, certain non-cash charges (such as non-cash unit-based compensation, impairments, loss on extinguishment of debt and unrealized losses on derivative contracts), major litigation costs net of recoveries, transaction-related costs, revenue deferral adjustment, loss on sale of assets, severance expense and selected charges that are unusual or non-recurring; less interest income, income tax benefit, unrealized gains on derivative contracts, equity in earnings of joint venture investments, gain on sale of assets and selected gains that are unusual or non-recurring. Adjusted EBITDA should not be considered an alternative to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP.

Adjusted EBITDA is a key metric used in measuring our compliance with our financial covenants under our debt agreements and is used as a supplemental measure by our management and by external users of 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 (net of capitalized costs), 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,
	2017			2016			2017			2016
Net cash provided by operating activities	$	14,552		$	11,256		$	25,836		$	41,203
Add (deduct):
Depreciation and amortization	(17,521		)	(31,449		)	(53,673		)	(68,898		)
Unit-based compensation	(827		)	(929		)	(1,241		)	(2,635		)
Amortization of deferred financing costs, original issuance discount and PIK interest	(889		)	(892		)	(2,719		)	(2,796		)
Gain (loss) on sale of assets, net	(186		)	179			5			12,755
Unrealized gain on financial instruments	(4		)	61			15			116
Equity in losses of joint venture investments	(3,218		)	(3,694		)	(9,865		)	(10,656		)
Distribution from joint venture investment	—			(350		)	—			(740		)
Impairment of assets	(1,120		)	(476		)	(1,769		)	(476		)
Gain on insurance proceeds	—			—			1,508			—
Other, net	63			63			411			247
Changes in operating assets and liabilities:
Trade accounts receivable, including affiliates	(11,865		)	(2,035		)	(12,503		)	(46,444		)
Prepaid expenses and other current assets	1,431			(1,679		)	(28		)	656
Other non-current assets	87			63			22			63
Accounts payable and accrued expenses, including affiliates	1,228			(3,123		)	1,912			24,685
Other liabilities	(789		)	445			1,778			(2,553		)
Net loss	$	(19,058	)	$	(32,560	)	$	(50,311	)	$	(55,473	)
Add (deduct):
Depreciation and amortization	$	17,521		$	31,449		$	53,673		$	68,898
Interest expense	9,931			8,598			28,670			26,601
Gain on insurance proceeds	—			—			(1,508		)	—
Income tax (benefit) expense	2			—			4			(2		)
Impairment of assets	1,120			476			1,769			476
Loss (gain) on sale of assets, net	186			(179		)	(5		)	(12,755		)
Revenue deferral adjustment	754			754			2,262			2,262
Unit-based compensation	827			929			1,241			2,635
Major litigation costs, net of recoveries	95			173			244			416
Transaction-related costs	1,387			—			1,387			6
Equity in losses of joint venture investments	3,218			3,694			9,865			10,656
Severance expense	63			—			2,811			16
Retention bonus funded by Holdings	91			898			91			2,694
Valley Wells' operating expense cap adjustment	—			—			—			2,406
Fees related to Equity Cure Agreement	—			12			—			589
Distribution from joint venture investment	—			350			—			740
Expenses related to shut-down of Conroe processing plant and conversion of Gregory processing plant	681			—			1,288			—
Other, net	(55		)	240			370			964
Adjusted EBITDA	$	16,763		$	14,834		$	51,851		$	51,129
Cash interest, net of capitalized costs	(9,182		)	(7,940		)	(26,428		)	(24,805		)
Income tax benefit (expense)	(2		)	—			(4		)	2
Maintenance capital expenditures	(1,135		)	(969		)	(2,063		)	(4,081		)
Distributable cash flow	$	6,444		$	5,925		$	23,356		$	22,245

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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,
	2017			2016			2017			2016
Revenues:
Revenues	$	122,099		$	123,043		$	364,456		$	316,673
Revenues - affiliates	48,379			21,619			129,458			72,418
Total revenues	170,478			144,662			493,914			389,091
Expenses:
Cost of natural gas and liquids sold	136,723			108,572			388,362			273,638
Operations and maintenance	14,278			17,781			43,779			54,173
Depreciation and amortization	17,521			31,449			53,673			68,898
General and administrative	6,557			6,831			19,616			22,879
Impairment of assets	1,120			476			1,769			476
Loss (gain) on sale of assets, net	186			(179		)	(5		)	(12,755		)
Total expenses	176,385			164,930			507,194			407,309

Income (loss) from operations	(5,907		)	(20,268		)	(13,280		)	(18,218		)
Other income (expense):
Equity in losses of joint venture investments	(3,218		)	(3,694		)	(9,865		)	(10,656		)
Interest expense	(9,931		)	(8,598		)	(28,670		)	(26,601		)
Gain on insurance proceeds	—			—			1,508			—
Total other expense	(13,149		)	(12,292		)	(37,027		)	(37,257		)
Loss before income tax benefit (expense)	(19,056		)	(32,560		)	(50,307		)	(55,475		)
Income tax benefit (expense)	(2		)	—			(4		)	2
Net loss	$	(19,058	)	$	(32,560	)	$	(50,311	)	$	(55,473	)

Other financial data:
Adjusted EBITDA	$	16,763		$	14,834		$	51,851		$	51,129

Maintenance capital expenditures	$	1,135		$	969		$	2,063		$	4,081
Growth capital expenditures	$	2,956		$	3,926		$	14,964		$	13,248

Operating data:
Average volume of processed gas (MMcf/d)	222			299			248			320
Average volume of NGLs produced (Bbls/d)	27,840			29,675			30,659			35,043
Average daily throughput Mississippi/Alabama (MMcf/d)	167			136			167			146

Realized prices on natural gas volumes ($/Mcf)	$	3.18		$	2.76		$	3.20		$	2.15
Realized prices on NGL volumes ($/gal)	0.53			0.41			0.52			0.34

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Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016

Volume and overview. Processed gas volumes decreased 77 MMcf/d, or 26%, to 222 MMcf/d during the three months ended September 30, 2017, compared to 299 MMcf/d during the three months ended September 30, 2016. This decrease was due primarily to the shut-down of the Conroe facility in the fourth quarter of 2016 and the temporary shut-down of our processing plants as a result of Hurricane Harvey during the three months ended September 30, 2017 compared to the three months ended September 30, 2016. Excluding the impact of Hurricane Harvey, processed gas volumes were 270 MMcf/d during the three months ended September 30, 2017.

NGLs produced at our processing plants for the three months ended September 30, 2017 averaged 27,840 Bbls/d, a decrease of 6%, or 1,835 Bbls/d, compared to 29,675 Bbls/d for the three months ended September 30, 2016. The decrease in NGLs produced is due primarily to the impact of Hurricane Harvey. Excluding the impact of Hurricane Harvey, NGLs produced at our processing plants averaged 33,500 Bbls/d.

Revenues. Our total revenues for the three months ended September 30, 2017 increased $25.8 million, or 18%, to $170.5 million compared to $144.7 million for the three months ended September 30, 2016. This increase was due primarily to an increase in realized prices in natural gas and NGLs, partially offset by a reduction in processed gas volumes. Revenue from sales of natural gas for the three months ended September 30, 2017 increased $28.9 million, or 38%, to $105.5 million compared to $76.6 million for the three months ended September 30, 2016.

Cost of natural gas and NGLs sold. Our cost of natural gas and NGLs sold for the three months ended September 30, 2017 was $136.7 million, compared to $108.6 million for the three months ended September 30, 2016. This increase of $28.1 million, or 26%, was due primarily to higher natural gas and NGL prices compared to the same period in 2016.

Operations and maintenance expenses. Operations and maintenance expenses for the three months ended September 30, 2017 were $14.3 million, compared to $17.8 million for the three months ended September 30, 2016 for a decrease of $3.5 million, or 20%. This decrease was due primarily to shutting down the Conroe and T2 Cogen facilities, idling of the Bonnie View fractionation facility, converting the Gregory facility to a compressor station and improved operating efficiencies at our facilities.

General and administrative expenses. General and administrative expenses for the three months ended September 30, 2017 were $6.6 million, compared to $6.8 million for the three months ended March 31, 2016. This decrease of $0.2 million, or 3%, was due primarily to cost-saving initiatives, partially offset by transaction-related expenses of $1.4 million during the three months ended September 30, 2017.

Depreciation and amortization expenses. Depreciation and amortization expense for the three months ended September 30, 2017 was $17.5 million, compared to $31.4 million for the three months ended September 30, 2016. The decrease of $13.9 million, or 44%, was due primarily to accelerating the depreciation of our Conroe and Gregory facilities beginning in August

2016 in response to management’s plans to shut down the Conroe facility and convert the Gregory facility to a compressor

station during the fourth quarter of 2016.

Equity in losses of joint venture investments. Our share of losses incurred by joint venture investments was $3.2 million for the three months ended September 30, 2017 and $3.7 million for the three months ended September 30, 2016. We pay our proportionate share of the joint ventures’ operating costs, excluding depreciation and amortization, through lease capacity payments. As a result, our share of the joint ventures’ losses is related primarily to the joint ventures’ depreciation and amortization.

Interest expense. For the three months ended September 30, 2017, interest expense was $9.9 million, compared to $8.6 million for the three months ended September 30, 2016. This increase of $1.3 million was due primarily to higher interest rates on borrowings.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016

Volume and overview. Processed gas volumes decreased 72 MMcf/d, or 23%, to 248 MMcf/d during the nine months ended September 30, 2017, compared to 320 MMcf/d during the nine months ended September 30, 2016. This decrease was due primarily to the shut-down of the Conroe facility in the fourth quarter of 2016 and the temporary shut-down of our processing plants as a result of Hurricane Harvey.

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NGLs produced at our processing plants for the nine months ended September 30, 2017 averaged 30,659 Bbls/d, a decrease of 13%, or 4,384, compared to 35,043 Bbls/d for the nine months ended September 30, 2016. The decrease in NGLs produced is due primarily to a decline in processed gas volumes.

Revenues. Our total revenues for the nine months ended September 30, 2017 increased $104.8 million, or 27%, to $493.9 million compared to $389.1 million for the nine months ended September 30, 2016. This increase was due primarily to an increase in realized prices in natural gas and NGLs. Revenue from sales of natural gas for the nine months ended September 30, 2017 increased $95.7 million, or 50%, to $288.4 million compared to $192.7 million the nine months ended September 30, 2016.

Cost of natural gas and NGLs sold. Our cost of natural gas and NGLs sold for the nine months ended September 30, 2017 was $388.4 million, compared to $273.6 million for the nine months ended September 30, 2016. This increase of $114.8 million, or 42%, was due primarily to a decline in processed gas volumes and higher natural gas and NGL prices as compared to the same period in 2016.

Operations and maintenance expenses. Operations and maintenance expenses for the nine months ended September 30, 2017 were $43.8 million, compared to $54.2 million for the nine months ended September 30, 2016 for a decrease of $10.4 million, or 19%. This decrease was due primarily to shutting down the Conroe and T2 Cogen facilities, idling of the Bonnie View fractionation facility, converting the Gregory facility to a compressor station and improved operating efficiencies at our facilities.

General and administrative expenses. General and administrative expenses for the nine months ended September 30, 2017 were $19.6 million, compared to $22.9 million for the nine months ended September 30, 2016. This decrease of $3.3 million, or 14%, was due primarily to cost-saving initiatives, including lower employee labor and professional service fees of $3.5 million, partially offset by transaction-related expenses of $1.4 million during the nine months ended September 30, 2017.

Depreciation and amortization expenses. Depreciation and amortization expense for the nine months ended September 30, 2017 was $53.7 million, compared to $68.9 million for the nine months ended September 30, 2016. The decrease of $15.2 million, or 22%, was due primarily to accelerating the depreciation of our Conroe and Gregory facilities beginning August

2016 in response to management’s plans to shut down the Conroe facility and convert the Gregory facility to a compressor

station during the fourth quarter of 2016.

Equity in losses of joint venture investments. Our share of losses incurred by joint venture investments was $9.9 million for the nine months ended September 30, 2017 and $10.7 million for the nine months ended September 30, 2016. We pay our proportionate share of the joint ventures’ operating costs, excluding depreciation and amortization, through lease capacity payments. As a result, our share of the joint ventures’ losses is related primarily to the joint ventures’ depreciation and amortization.

Interest Expense. For the nine months ended September 30, 2017, interest expense was $28.7 million, compared to $26.6 million for the nine months ended September 30, 2016. This increase of $2.1 million was due primarily to higher interest rates on borrowings.

Liquidity and Capital Resources

Sources of Liquidity

Our primary sources of liquidity are cash generated from operations, cash raised through issuances of additional debt securities and borrowings under our Senior Credit Facilities (as defined in Note 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, such as for expansion projects and acquisitions, 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.

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

On December 29, 2016, we entered into the Fifth Amendment, pursuant to which we received a full waiver for all defaults or events of default arising out of our failure to comply with the financial covenant to maintain a Consolidated Total Leverage Ratio less than 5.00 to 1.00 for the quarter ended September 30, 2016.

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 $145 million (then further reduced to $140 million on September 30, 2017) 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 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. Prior to the Ratio Compliance Date, we will be required to maintain minimum levels of Consolidated EBITDA on a quarterly basis and be subject to certain covenants and restrictions related to liquidity and capital expenditures. See Notes 1 and 5 to our condensed consolidated financial statements.

As of November 6, 2017, we had $531.0 million in outstanding borrowings under our Senior Credit Facilities (as defined in Note 5 to our condensed consolidated financial statements). Under our five-year revolving credit facility (the "Credit Facility"), pursuant to our Third A&R Revolving Credit Agreement, we currently have the ability to borrow up to $140.0 million less any letters of credit amounts outstanding, which as of November 6, 2017 provided us access to $21.3 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,
	2017		2016		2017		2016
Maintenance capital expenditures	$	1,135	$	969	$	2,063	$	4,081
Growth capital expenditures	2,956		3,926		14,964		13,248
Capital expenditures	$	4,091	$	4,895	$	17,027	$	17,329

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 and required safety and reliability upgrades to our facilities. Our growth capital expenditures during the nine months ended September 30, 2016, primarily relate to various expansion and improvement projects primarily in our South Texas assets.

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

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

We believe that cash from operations, cash on hand and the Investment Agreement with Holdings, as backstopped by the Sponsors, will provide sufficient liquidity to meet future short-term capital requirements through at least twelve months from the date that the financial statements included in this Form 10-Q were issued. Growth projects are a key element of our business strategy. We intend to finance any required growth capital through several sources, including operating cash flows, borrowings under our Senior Credit Facilities and the issuance of additional debt securities. The timing, size or success of any acquisition or expansion effort and the associated potential capital commitments are unpredictable. To consummate acquisitions or capital projects, we may require access to additional capital. Our access to capital long-term will depend on our future operating performance, financial condition and credit rating and, more broadly, on the availability of debt financing, which will be affected by prevailing conditions in our industry, the economy and the financial markets and other financial and business factors, many of which are beyond our control.

Cash Flows

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



	Nine Months Ended September 30,
	2017			2016
Net cash provided by operating activities	$	25,836		$	41,203
Net cash used in investing activities	(3,589		)	(1,797		)
Net cash used in financing activities	(28,821		)	(46,639		)

Operating cash flows — The decrease in cash provided by operating activities of $15.4 million was due primarily to higher settlements of affiliated accounts receivable during the nine months ended September 30, 2016 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, 2017 was $3.6 million, compared to net cash used in investing activities of $1.8 million for the nine months ended September 30, 2016. The decrease of $1.8 million relates primarily to net cash proceeds received from the sales of assets of $20.7 million during the nine months ended September 30, 2016 compared to $3.0 million for the nine months ended September 30, 2017, partially offset by $8.9 million received from aid in construction payments and $2.0 million of insurance proceeds from property damage claims, net of expenditures during the nine months ended September 30, 2017.

Financing cash flows — Net cash used in financing activities for the nine months ended September 30, 2017 was $28.8 million, compared to $46.6 million for the nine months ended September 30, 2016. The decrease of $17.8 million was due primarily to $35.1 million of additional net paydowns on our Credit Facility during the nine months ended September 30, 2016 as compared to the nine months ended September 30, 2017, partially offset by $12.4 million received for the fourth quarter 2015 and first quarter 2016 equity cures provided to us by Holdings during the nine months ended September 30, 2016.

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.

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Critical Accounting Policies and Estimates

Our critical accounting policies are consistent with those described in our 2016 Annual Report on Form 10-K.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

Our interest rate risk and commodity price, market and credit risks are discussed in our 2016 Annual Report on Form 10-K and there have been no material changes in those exposures from December 31, 2016 to September 30, 2017.

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 2017 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.

From time to time, we may be involved in various legal or governmental proceedings and litigation arising in the ordinary course of business. In management’s opinion, the resolution of such matters is not expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows. See Note 6 to our condensed consolidated financial statements.

TPL SouthTex Processing Company, LP v. FL Rich Gas Services, LP; Case No. 01-17-0001-9892; pending in the American Arbitration Association

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”). This demand related to the operation of T2 EF Cogeneration Holdings LLC, a joint venture with Targa in which each of TPL and FL Rich own 50% of the membership interests (“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 fidicuary 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. No arbitration hearing has yet been scheduled. We believe this matter is without merit and we intend to defend the arbitration vigorously. Because this matter is in an early stage, we are unable to predict its outcome and the possible loss or range of loss, if any, associated with its resolution or any potential effect the matter may have on our financial position. Depending on the outcome or resolution of this matter, it could have a material effect on our financial position.

Victor Henneke, Jr., et al. v. Southcross Energy Partners GP, LLC Cause No. DC-16-139, 229th Judicial District, Duval County, Texas

Our General Partner has been named as a defendant in a lawsuit filed April 29, 2016 in Duval County, Texas styled Victor Henneke, Jr., et al. v. Southcross Energy Partners GP, LLC 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

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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. The Judge ultimately elected to not enter either jury verdict and a new trial was ordered by the court on September 29, 2017. The Judge subsequently resigned from the bench on October 2, 2017. Our insurance carriers are pursuing an appeal to the Texas Fourth Court of Appeals to enter the first of the two award amounts as determined by the jury in the trial ending September 22, 2017. In addition, a new trial is pending the appointment or replacement of the Judge who resigned.

Item 1A. Risk Factors.

Our Risk Factors are consistent with those disclosed in Part I, Item 1A Risk Factors of our 2016 Annual Report on Form 10-K.

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

As discussed in Note 2 to our condensed consolidated financial statements, on August 11, 2017, 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, 2017. In connection with the issuance of the Class B PIK Units, our General Partner made a capital contribution in exchange for the issuance of 6,325 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 13, 2017	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
2.1		Agreement and Plan of Merger, dated October 31, 2017 by and among American Midstream Partners, L.P., American Midstream GP, LLC, Southcross Energy Partners, L.P. and Southcross Energy Partners GP, LLC (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K dated November 2, 2017).
2.2****		Contribution Agreement, dated October 31, 2017 by and among American Midstream Partners, L.P., American Midstream GP, LLC and Southcross Holdings LP
3.1		Certificate of Limited Partnership of Southcross Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).
3.2		Third Amended and Restated Agreement of Limited Partnership of Southcross Energy Partners, L.P., dated as of August 4, 2014 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated August 4, 2014).
3.3		Certificate of Formation of Southcross Energy Partners GP, LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1/A (Commission File No. 333-180841)).
3.4		Second Amended and Restated Limited Liability Company Agreement of Southcross Energy Partners GP, LLC, dated as of August 4, 2014 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K dated August 4, 2014).
10.1		Letter Agreement, dated October 31, 2017 by and among Southcross Holdings LP and Southcross Energy Partners, L.P. (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated November 2, 2017).
10.2*		Amendment to the Southcross Energy Partners, L.P. Non-Employee Director Deferred Compensation Plan, dated October 31, 2017 (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K dated November 2, 2017).
31.1**		Certification of Chief Executive Officer required by Rule 13a-14(a)/15d-14(a).
31.2**		Certification of Chief Financial Officer required by Rule 13a-14(a)/15d-14(a).
32.1***		Certifications of Chief Executive Officer and Chief Financial Officer required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
101.INS**†		XBRL Instance Document.
101.SCH**†		XBRL Taxonomy Extension Schema.
101.CAL**†		XBRL Taxonomy Extension Calculation Linkbase.
101.DEF**†		XBRL Taxonomy Extension Definition Linkbase.
101.LAB**†		XBRL Taxonomy Extension Label Linkbase.
101.PRE**†		XBRL Extension Presentation Linkbase.

* Management contracts or compensatory plans or arrangement.

** Filed herewith.

*** Furnished herewith.

**** Certain schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule will be furnished supplementally to the SEC upon request provided, however that Southcross Energy Partners, L.P. may request confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended, for any schedules so furnished.

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