Edgar Filing: Southcross Energy Partners, L.P.

SEC 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 March 31, 2016



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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer o		Accelerated filer x

Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

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

As of May 5, 2016, the registrant has 36,542,194 common units outstanding, 12,213,713 subordinated units outstanding and 15,958,990 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 March 31, 2016 and December 31, 2015	4

	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2016 and 2015	5

	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2016 and 2015	6

	Condensed Consolidated Statements of Changes in Partners’ Capital for the Three Months Ended March 31, 2016 and 2015	7

	Notes to Condensed Consolidated Financial Statements (Unaudited)	8

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

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	37

ITEM 4.	Controls and Procedures	38

PART II — OTHER INFORMATION		38

ITEM 1.	Legal Proceedings	38

ITEM 1A.	Risk Factors	38

ITEM 6.	Exhibits	38

SIGNATURES		39

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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)



	March 31, 2016		December 31, 2015
ASSETS
Current assets:
Cash and cash equivalents	$	12,775	$	11,348
Trade accounts receivable	28,613		39,585
Accounts receivable - affiliates	51,858		49,734
Prepaid expenses	3,070		3,915
Deposits to suppliers	15,300		—
Other current assets	798		1,256
Total current assets	112,414		105,838

Property, plant and equipment, net	1,051,856		1,066,001
Investments in joint ventures	141,780		140,526
Other assets	6,839		6,595
Total assets	$	1,312,889	$	1,318,960

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	44,395	$	66,458
Accounts payable - affiliates	10,816		7,871
Current portion of long-term debt	4,500		4,500
Senior unsecured PIK notes	14,229		—
Other current liabilities	2,398		10,406
Total current liabilities	76,338		89,235

Long-term debt	607,011		604,518
Other non-current liabilities	9,682		3,871
Total liabilities	693,031		697,624

Commitments and contingencies (Note 7)

Partners' capital:
Common units (28,512,017 and 28,420,619 units outstanding as of March 31, 2016 and December 31, 2015, respectively; 8,029,729 units issuable as of March 31, 2016)	277,401		271,236
Class B Convertible units (15,958,990 units issued and outstanding as of March 31, 2016 and December 31, 2015)	296,310		300,596
Subordinated units (12,213,713 units issued and outstanding as of March 31, 2016 and December 31, 2015)	34,641		37,920
General partner interest	11,506		11,584
Total partners' capital	619,858		621,336
Total liabilities and partners' capital	$	1,312,889	$	1,318,960

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 March 31,
	2016			2015
Revenues:
Revenues	$	95,455		$	178,491
Revenues - affiliates	24,271			7,447
Total revenues	119,726			185,938

Expenses:
Cost of natural gas and liquids sold	79,447			141,115
Operations and maintenance	16,778			22,555
Depreciation and amortization	18,541			17,031
General and administrative	7,886			7,805
Loss on sale of assets, net	—			218
Total expenses	122,652			188,724

Loss from operations	(2,926		)	(2,786		)
Other expense:
Equity in losses of joint venture investments	(3,429		)	(3,552		)
Interest expense	(9,170		)	(7,498		)
Total other expense	(12,599		)	(11,050		)
Loss before income tax benefit (expense)	(15,525		)	(13,836		)
Income tax benefit (expense)	5			(69		)
Net loss	(15,520		)	(13,905		)
General partner unit in-kind distribution	—			(76		)
Net loss attributable to Holdings	—			(3,154		)
Net loss attributable to partners	$	(15,520	)	$	(10,827	)

Earnings per unit and distributions declared
Net loss allocated to limited partner common units	$	(7,643	)	$	(4,936	)
Weighted average number of limited partner common units outstanding	28,446			23,801
Basic and diluted loss per common unit	$	(0.27	)	$	(0.21	)

Net loss allocated to limited partner subordinated units	$	(3,280	)	$	(2,533	)
Weighted average number of limited partner subordinated units outstanding	12,214			12,214
Basic and diluted loss per subordinated unit	$	(0.27	)	$	(0.21	)
Distributions declared and paid per common unit	$	—		$	0.40

See accompanying notes.

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SOUTHCROSS ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)



	Three Months Ended March 31,
	2016			2015
Cash flows from operating activities:
Net loss	$	(15,520	)	$	(13,905	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization	18,541			17,031
Unit-based compensation	981			813
Amortization of deferred financing costs and PIK interest	1,073			825
Loss on sale of assets, net	—			218
Unrealized loss on financial instruments	30			167
Equity in losses of joint venture investments	3,429			3,552
Distribution from joint venture investment	390			—
Other, net	(121		)	11
Changes in operating assets and liabilities:
Trade accounts receivable, including affiliates	9,099			18,307
Prepaid expenses and other current assets	1,173			(297		)
Deposits paid to suppliers	(15,300		)	—
Other non-current assets	(280		)	170
Accounts payable and accrued liabilities	(18,663		)	(27,140		)
Other liabilities, including affiliates	(2,004		)	2,296
Net cash provided by (used in) operating activities	(17,172		)	2,048
Cash flows from investing activities:
Capital expenditures	(5,474		)	(41,002		)
Insurance proceeds from property damage claims, net of expenditures	125			545
Proceeds from sales of assets	—			4,368
Investment contribution to joint venture investments	(5,072		)	(2,349		)
Net cash used in investing activities	(10,421		)	(38,438		)
Cash flows from financing activities:
Borrowings under our credit facility	3,110			50,000
Repayments under our credit facility	(250		)	(15,000		)
Repayments under our term loan agreement	(1,125		)	(1,125		)
Payments on capital lease obligations	(103		)	(140		)
Financing costs	(86		)	(6		)
Tax withholdings on unit-based compensation vested units	(57		)	—
Payments of distributions and distribution equivalent rights	—			(13,368		)
Expenses paid by Holdings on behalf of Valley Wells' assets	—			14,610
Issuance of senior unsecured PIK notes	14,000			—
Valley Wells operating expense cap adjustment	1,647			—
Equity contribution from Holdings	11,884			—
Net cash provided by financing activities	29,020			34,971

Net increase (decrease) in cash and cash equivalents	1,427			(1,419		)
Cash and cash equivalents — Beginning of period	11,348			1,649
Cash and cash equivalents — End of period	$	12,775		$	230

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, 2015	$	271,236		$	300,596		$	37,920		$	11,584		$	621,336
Net loss	(7,644		)	(4,286		)	(3,279		)	(311		)	(15,520		)
Unit-based compensation on long-term incentive plan	981			—			—			—			981
Accrued distribution equivalent rights on long-term incentive plan	10			—			—			—			10
Tax withholdings on unit-based compensation vested units	(57		)	—			—			—			(57		)
Interest on receivable due from Holdings	—			—			—			233			233
Equity contribution from Holdings	11,884			—			—			—			11,884
Valley Wells' operating expense cap adjustment	991			—			—			—			991
BALANCE - March 31, 2016	$	277,401		$	296,310		$	34,641		$	11,506		$	619,858



	Partners' Capital
	Limited Partners
	Common			Class B Convertible			Subordinated			General Partner			Southcross Holdings' equity in contributed subsidiaries			Total
BALANCE - December 31, 2014	$	259,735		$	298,833		$	48,831		$	12,385		$	77,320		$	697,104
Net loss	(4,902		)	(3,119		)	(2,513		)	(217		)	(3,154		)	(13,905		)
Class B Convertible unit in-kind distribution	(2,405		)	3,712			(1,232		)	(75		)	—			—
Unit-based compensation on long-term incentive plan	948			—			—			—			—			948
Cash distributions and distribution equivalent rights paid	(9,520		)	—			(3,432		)	(416		)	—			(13,368		)
Accrued distribution equivalent rights on long-term incentive plan	(342		)	—			—			—			—			(342		)
General partner unit in-kind distribution	(50		)	—			(26		)	76			—			—
Expenses paid by Holdings on behalf of Valley Wells' assets	—			—			—			—			14,610			14,610
BALANCE - March 31, 2015	$	243,464		$	299,426		$	41,628		$	11,753		$	88,776		$	685,047

See accompanying notes.

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SOUTHCROSS ENERGY PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. ORGANIZATION AND DESCRIPTION OF BUSINESS

Organization

Southcross Energy Partners, L.P. (the "Partnership," "Southcross," "we," "our" or "us") is a Delaware limited partnership formed in April 2012. Our common units are listed on the New York Stock Exchange under the symbol “SXE.” We are a master limited partnership, headquartered in Dallas, Texas, that provides natural gas gathering, processing, treating, compression and transportation services and NGL fractionation and transportation services. We also source, purchase, transport and sell natural gas and NGLs. Our assets are located in South Texas, Mississippi and Alabama and include four gas processing plants, two fractionation facilities and our 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 units and a portion of our common units. Our General Partner owns an approximate 2.0% interest in us and all of our incentive distribution rights.

Following the emergence of Holdings from its Chapter 11 reorganization proceeding on April 13, 2016 (as discussed below), 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 equity interest.

Holdings Chapter 11 Reorganization

On March 28, 2016, Holdings and certain of its subsidiaries (excluding us, our General Partner and our subsidiaries) filed a pre-packaged plan of reorganization (the “POR”) under Chapter 11 of the U.S. Bankruptcy Code in the Southern District of Texas to restructure its debt obligations and strengthen its balance sheet. Our operations, customers, suppliers, partners and other constituents were excluded from such proceeding. On April 11, 2016, the bankruptcy court confirmed Holdings’ POR, and on April 13, 2016, Holdings and its subsidiaries emerged from its bankruptcy with the Lenders being issued 33.34% of the limited partner interests in Holdings in exchange for the elimination of certain funded debt obligations. EIG and Tailwater each contributed $85 million in cash (or $170 million in the aggregate) in exchange for each Sponsor receiving 33.33% of the limited partner interests in Holdings. In addition, Holdings committed to provide us $50 million (as part of the Equity Cure Agreement defined below), out of the $170 million in new equity contributed to Holdings from the Sponsors, to provide us with sufficient liquidity to comply with the applicable financial covenants set forth in our credit agreement. Holdings also paid all of the receivable due to us as of February 29, 2016. We believe Holdings’ reorganization and POR will enhance our liquidity position, strengthen our balance sheet and position Holdings to continue to support our business and growth.

Liquidity Consideration

Energy commodity prices have declined substantially since 2014 due to a number of factors, including a continuing growth of supply, slowdown or decline in demand and challenges in global economic, financial and monetary markets. Sustained low natural gas, NGL or crude oil prices have negatively impacted natural gas and oil exploration and production activity levels industry-wide. Our future cash flow will be materially adversely affected if this prolonged pricing deterioration continues for the commodities we sell or if a material reduction in drilling for oil or natural gas continues in the geographic areas in which we operate, including the Eagle Ford Shale region.

The majority of our revenue is derived from fixed-fee 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.

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Note 6, we have the right to cure such a Financial Covenant Default (as defined in Note 6) by either our Sponsors or Holdings purchasing equity interests in or making capital contributions (an equity cure) resulting in, among other things, proceeds that, if added to consolidated EBITDA, would result in us satisfying the Financial Covenants. Once such an equity cure is made, it is included in our consolidated EBITDA calculation in any rolling twelve month period that includes the quarter that was cured. Should there be an event of default under the Credit Facility, and such default is not cured, we also would experience a cross default under our Term Loan Agreement (defined in Note 6) and all of our debt would become due and payable to our lenders.

On March 17, 2016, we entered into an equity cure contribution agreement (the “Equity Cure Agreement”) with Holdings whereby we have the right to cure any default with respect to our Financial Covenants by having Holdings purchase equity interests in or make capital contributions to us, in an aggregate amount of up to $50 million. The fair value of the Equity Cure Agreement was not material at inception. In connection with Holdings' Chapter 11 reorganization, and pursuant to the terms of the Equity Cure Agreement, Holdings has committed to contribute up to $50 million to us (the “Contribution Amount”) to ensure we have sufficient liquidity to comply with applicable Financial Covenants through the quarter ended December 31, 2016. In exchange for the Contribution Amount, we will issue Holdings a number of our common units representing limited partner interests equal to, subject to certain exceptions, (i) the applicable Contribution Amount divided by (ii) a common unit reference price (“Reference Price”) equal to the volume weighted daily average price of the common units on the New York Stock Exchange (“VWAP”) calculated for a period of 15 trading days ending two trading days prior to the contribution by Holdings. Notwithstanding the VWAP calculation, the Reference Price will be no less than $0.89 per common unit and no greater than $1.48 per common unit (the “Range”), and if the VWAP is within the Range for a period of 15 trading days, the first of which is April 7, 2016, such VWAP will be the Reference Price for all common units issued in exchange for the Contribution Amount. The $0.5 million in cash necessary to cure the non-compliance in the first quarter of 2016 will be contributed to us within 15 days following the issuance of these financial statements. In accordance with the requirements above and the amount funded for this equity cure, Holdings will be issued between 0.4 million and 0.6 million common units. The number of units to be issued to Holdings in exchange for this contribution has yet to be determined since the required number of days to calculate the VWAP has not been reached as of the date of the issuance of these financial statements.

As of March 31, 2016, we were not in compliance with the consolidated total leverage ratio of our Financial Covenants absent an equity cure of $0.5 million within approximately 15 days following the issuance of these financial statements. We believe that we will have the ability to fund this equity cure through the Equity Cure Agreement. We used $11.9 million of the $50 million equity commitment from Holdings to fund an equity cure as of December 31, 2015 in order to stay in compliance with the consolidated total leverage ratio of our Financial Covenants. In accordance with the requirements above and the amount funded for this equity cure, Holdings was issued 8,029,729 common units on May 2, 2016. We anticipate funding additional equity cures needed to maintain compliance with our Financial Covenants through the end of 2016 with the equity commitment from Holdings.

Therefore, these financial statements have been presented as we continue as a going concern. See Note 6.

On January 7, 2016, in response to our need for additional liquidity, we issued at par senior unsecured PIK notes in the aggregate principal amount of $14.0 million (the "PIK Notes") to affiliates of EIG and Tailwater, that bear interest at a rate of 7% due January 7, 2017. Contemporaneous with the resolution of Holdings’ bankruptcy proceedings, the PIK Notes and the related interest were repaid in full.

Distribution Suspension

The board of directors of our General Partner voted not to pay a quarterly distribution with respect to the fourth quarter of 2015 and the first quarter of 2016 and instead reserved 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. The board of directors and management will continue to evaluate the Partnership's ability to reinstate the distribution in future periods. See Note 3.

Segments

Our chief operating decision-maker is our General Partner’s 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.

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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 2015 Annual Report on Form 10-K (“2015 Annual Report on Form 10-K”). The condensed consolidated financial statements as of March 31, 2016 and December 31, 2015, and for the three months ended March 31, 2016 and 2015, are unaudited and have been prepared on the same basis as the audited financial statements included in our 2015 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.

We recognized the 2015 Holdings Acquisition (defined in Note 2) at Holdings’ historical cost because the acquisition was executed by entities under common control. Thus, the difference between consideration paid and Holdings’ historical cost (net book value) at May 7, 2015, the date on which the 2015 Holdings Acquisition closed, was recorded as an increase to partners’ capital. Due to the common control aspect, the 2015 Holdings Acquisition was accounted for by the Partnership on an “as if pooled” basis for the periods during which common control existed which began on August 4, 2014. See Note 2.

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 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 2015 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.

Significant Accounting Policies

During the first quarter of 2016, there were no material changes to our significant accounting policies described in Note 1 of our 2015 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 below to determine their impact, if any, on our consolidated financial statements. We are evaluating the impact of each pronouncement on our consolidated financial statements.

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

In March 2016, the FASB issued a pronouncement amending the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. This standard will become effective beginning in 2017.

In March 2016, the FASB issued a pronouncement amending the requirement to adopt retroactively the equity method of accounting. The pronouncement eliminates the requirement that when an investment qualifies for use of the equity method as a

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result of an increase in the level of ownership interest or degree of influence, an investor must adjust the investment, results of operations, and retained earnings retroactively on a step-by-step basis as if the equity method had been in effect during all previous periods that the investment had been held. The new guidance requires that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor’s previously held interest and adopt the equity method of accounting as of the date the investment becomes qualified for equity method accounting. Therefore, upon qualifying for the equity method of accounting, no retroactive adjustment of the investment is required. In addition, the pronouncement requires that an entity that has an available-for sale equity security that becomes qualified for the equity method of accounting recognize through earnings the unrealized holding gain or loss in accumulated other comprehensive income at the date the investment becomes qualified for use of the equity method. This standard will become effective beginning in 2017.

2. ACQUISITIONS

Holdings Drop-Down Acquisition. On May 7, 2015, we completed the acquisition of gathering, treating, compression and transportation assets (the “2015 Holdings Acquisition”) consisting of the Valley Wells sour gas gathering and treating system (the "Valley Wells System"), compression assets that are part of the Valley Wells and Lancaster gathering and treating systems (the "Compression Assets") and two NGL pipelines pursuant to a Purchase, Sale and Contribution Agreement among Holdings, TexStar Midstream Utility, LP, Frio LaSalle Pipeline, LP (“Frio”), us and certain of our subsidiaries. Total consideration for the assets was $77.6 million, consisting of $15.0 million in cash and 4.5 million new common units, valued as of the date of closing and issued to Holdings. We also assumed the remaining capital expenditures for the completion of the NGL pipelines that were under construction.

The 2015 Holdings Acquisition was deemed a transaction between entities under common control and, as such, was accounted for on an “as if pooled” basis for all periods which common control existed (which began on August 4, 2014). The Partnership’s financial results retrospectively include the financial results of the Valley Wells System and Compression Assets for all periods ending after August 4, 2014, the date of the Holdings Transaction, and before May 7, 2015. The acquired NGL pipelines were accounted for as an asset acquisition and were included in the historical financial statements beginning on May 7, 2015. As a carve-out transaction, the 2015 Holdings Acquisition had no cash accounts. As such, accounts receivable and accounts payable, along with certain other assets and liabilities that would be settled in cash, were the rights and obligations of Holdings as of December 31, 2014. Given their nature and the fact that carve-out financial statements are meant to represent an entity’s operations as if it had existed as of the time common control occurred, we have presented these amounts as third-party receivables and payables.

The amount of the consideration paid below Holdings’ net book value of the assets received and liabilities assumed of the 2015 Holdings Acquisition was recorded as an increase to partners’ capital as summarized as follows (in thousands):



Consideration paid⁽¹⁾	$	77,640
Total net assets contributed	107,356
Net assets contributed in excess of consideration paid	$	29,716
Allocation of increase to partners' capital:
Common limited partner interest	$	14,806
Class B Convertible limited partner interest	7,929
Subordinated limited partner interest	6,387
General Partner interest	594
Total increase to partners' capital	$	29,716

(1) This amount was calculated as follows: $15.0 million of cash plus 4.5 million new common units at an issue price of $13.92, the closing price of the Partnership’s common units on May 7, 2015.

Supplemental Disclosures - As If Pooled Basis. As noted above, the 2015 Holdings Acquisition was between commonly controlled entities which required that we account for the acquisitions in a manner similar to a pooling of interests. As a result, the historical financial statements of the Partnership and the Valley Wells System and Compression Assets have been combined to reflect the historical operations, financial position and cash flows from the date common control began on August 4, 2014. Revenues and net income for the previously separate entities and the combined amounts for the three months ended March 31, 2015, are as follows (in thousands):

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	Three Months Ended March 31, 2015
Partnership revenues	$	180,549
Valley Wells System and Compression Assets revenue	5,389
Combined revenues	$	185,938

Partnership net loss	$	(10,751	)
Valley Wells System and Compression Assets net loss	(3,154		)
Combined net loss	$	(13,905	)

3. NET LOSS PER LIMITED PARTNER UNIT AND DISTRIBUTIONS

Net Loss Per Limited Partner Unit

The following is a reconciliation of net loss attributable to limited partners and the limited partner units used in the basic and diluted earnings per unit calculations for the three months ended March 31, 2016 and 2015 (in thousands, except unit and per unit data):



	Three Months Ended March 31,
	2016			2015
Net loss	$	(15,520	)	$	(13,905	)
General partner unit in-kind distribution	—			(76		)
Net loss attributable to Holdings	—			(3,154		)
Net loss attributable to partners	$	(15,520	)	$	(10,827	)

General partner's interest ⁽¹⁾	$	(311	)	$	(239	)
Class B Convertible limited partner interest ⁽¹⁾	(4,286		)	(3,119		)
Limited partners' interest ⁽¹⁾
Common	$	(7,643	)	$	(4,936	)
Subordinated	(3,280		)	(2,533		)

(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 (“Class B Convertible Units”) interest is calculated based on the allocation of only net losses for the period.



	Three Months Ended March 31,
Common Units	2016			2015
Interest in net loss	$	(7,643	)	$	(4,936	)
Effect of dilutive units - numerator ⁽¹⁾	—			—
Dilutive interest in net loss	$	(7,643	)	$	(4,936	)

Weighted-average units - basic	28,445,879			23,800,943
Effect of dilutive units - denominator ⁽¹⁾	—			—
Weighted-average units - dilutive	28,445,879			23,800,943

Basic and diluted net loss per common unit	$	(0.27	)	$	(0.21	)

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	Three Months Ended March 31,
Subordinated Units	2016			2015
Interest in net loss	$	(3,280	)	$	(2,533	)
Effect of dilutive units - numerator⁽¹⁾	—			—
Dilutive interest in net loss	$	(3,280	)	$	(2,533	)

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

Basic and diluted net loss per subordinated unit	$	(0.27	)	$	(0.21	)

(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 was 2,081 for the three months ended March 31, 2015.

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.

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 Credit Agreement Amendment (as defined in Note 6) imposed additional restrictions on our ability to declare and pay quarterly cash distributions with respect to our subordinated units. See Note 6.

Cash Distributions

Holdings did not receive a distribution for the first quarter of 2015 in respect of the 4.5 million common units acquired by it in connection with the 2015 Holdings Acquisition.

Paid In-Kind Distributions

Class B Convertible Units. As of March 31, 2016, the Class B Convertible Units consisted of 15,958,990 of such units including the additional Class B Convertible Units issued in-kind as a distribution (“Class B PIK Units”). The Class B Convertible Units are not participating securities for purposes of the earnings per unit calculation. Commencing with the quarter ended September 30, 2014 and until converted, as long as certain requirements are met, the holders of the Class B Convertible Units will receive quarterly distributions in an amount equal to $0.3257 per unit. These distributions will be paid quarterly in Class B PIK Units within 45 days after the end of each quarter. Our General Partner was entitled, and has exercised its right, to retain its 2.0% general partner interest in us in connection with the original issuance of the Class B Convertible Units. In connection with future distributions of Class B PIK Units, the General Partner is entitled to a corresponding distribution to maintain its 2.0% general partner interest in us. The Class B Convertible Units have the same rights, preferences and privileges, and are subject to the same duties and obligations, as our common units, with certain exceptions. See Note 8.

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Although we have suspended distributions to holders of our Class B Convertible Units, such paid in-kind (“PIK”) distributions continue to accumulate. Under the terms of our Partnership Agreement, we are required to pay or set aside for payment all accumulated but unpaid PIK distributions with respect to the Class B Convertible Units prior to or contemporaneously with resuming any distribution with respect to our units. As of March 31, 2016, we have accumulated, but not yet issued, 563,494 Class B Convertible Units to Holdings and 11,499 general partner units to our General Partner. On May 6, 2016, the board of directors of our General Partner approved the issuance of these units.

4. FINANCIAL INSTRUMENTS

Fair Value Measurements

We apply recurring fair value measurements to our financial assets and liabilities. In estimating fair value, we generally use a market approach and incorporate assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and/or the risks inherent in the inputs to the valuation techniques. The fair value measurement inputs we use vary from readily observable inputs that represent market data obtained from independent sources to unobservable inputs that reflect our own market assumptions that cannot be validated through external pricing sources. Based on the observability of the inputs used in the valuation techniques, the financial assets and liabilities carried at fair value in the financial statements are classified as follows:


•	Level 1—Represents unadjusted quoted market prices in active markets for identical assets or liabilities that are accessible at the measurement date. This category primarily includes our cash and cash equivalents, accounts receivable and accounts payable.


•	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 the debt funded through our credit facilities 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.

Derivative Financial Instruments

Interest Rate Derivative Transactions

We enter into interest rate swap contracts whereby we receive a floating rate and pay a fixed rate to reduce the risk associated with the variability of interest rates for our term loan borrowings. Our interest rate swap position was as follows (in thousands):



						Estimated Fair Value
Notional Amount		Fixed Rate		Effective Date	Maturity Date	March 31, 2016
$	50,000	1.198	%	September 30, 2014	June 30, 2016	$	(25	)
50,000		1.196	%	September 30, 2014	June 30, 2016	(25		)
100,000		1.195	%	June 30, 2015	January 1, 2017	(140		)
						$	(190	)

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Effectively, 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	March 31, 2016
$	20,000	1.500	%	December 31, 2014	December 31, 2016	$	—
80,000		3.000	%	June 30, 2015	June 30, 2017	1
50,000		3.000	%	December 31, 2015	December 31, 2017	1
						$	2

These interest rate derivatives are not designated as cash flow hedges 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 March 31, 2016 or December 31, 2015.

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
	March 31, 2016			December 31, 2015
Current interest rate derivative assets	$	1		$	6
Non-current interest rate derivative assets	1			4
Current interest rate derivative (liabilities)	(190		)	(169		)
Total interest rate derivatives	$	(188	)	$	(159	)

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



	Three Months Ended March 31,
	2016		2015
Unrealized loss on interest rate derivatives	$	30	$	56
Realized loss on interest rate derivatives	99		104

Commodity Swaps

In our normal course of business, periodically we enter into month-ahead swap contracts to hedge our exposure to certain intra-month natural gas index pricing risk. We had no outstanding month-ahead swap contracts as of March 31, 2016 and December 31, 2015. We define these contracts as Level 2 because the index price associated with such contracts is observable and tied to a similarly quoted first-of-the-month natural gas index price.

The realized and unrealized gain/loss on these derivatives, recognized in revenues in our statements of operations, were as follows (in thousands):



	Three Months Ended March 31,
	2016		2015
Realized gain on commodity swap derivatives	$	—	$	125
Unrealized loss on commodity swap derivatives	—		(111		)

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5. LONG-LIVED ASSETS

Property, Plant and Equipment

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



	Estimated Useful Life (yrs)	March 31, 2016			December 31, 2015
Pipelines	15-30	$	545,977		$	542,790
Gas processing, treating and other plants	15	555,724			547,253
Compressors	7-15	74,566			72,750
Rights of way and easements	15	46,696			46,692
Furniture, fixtures and equipment	5	9,252			9,252
Capital lease vehicles	3-5	2,442			2,442
Total property, plant and equipment		1,234,657			1,221,179
Accumulated depreciation and amortization		(231,484		)	(212,991		)
Total		1,003,173			1,008,188

Construction in progress		22,603			32,214
Land and other		26,080			25,599
Property, plant and equipment, net		$	1,051,856		$	1,066,001

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

Intangible Assets

Intangible assets of $1.4 million and $1.5 million as of March 31, 2016 and December 31, 2015, 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.

6. LONG-TERM DEBT

Our outstanding debt and related information at March 31, 2016 and December 31, 2015 are as follows (in thousands):



	March 31, 2016			December 31, 2015
Revolving credit facility due 2019	$	184,555		$	181,695
Term loans (including original issue discount of $1.7 million and $1.8 million as of March 31, 2016 and December 31, 2015, respectively) due 2021	440,421			441,464
Total long-term debt (including current portion)	624,976			623,159
Current portion of long-term debt	(4,500		)	(4,500		)
Deferred financing costs	(13,465		)	(14,141		)
Total long-term debt	$	607,011		$	604,518
Senior unsecured PIK notes	$	14,229		$	—
Outstanding letters of credit	$	15,195		$	18,305
Remaining unused borrowings	$	250		$	—



	Three Months Ended March 31,
	2016			2015
Weighted average interest rate	5.2		%	5.1		%
Average outstanding borrowings	$	626,353		$	512,093
Maximum borrowings	$	628,055		$	522,750

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Senior Credit Facilities

Our long-term debt arrangements consist of (a) the Third A&R Revolving Credit Agreement (as defined in Note 1) and (b) 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 (the “Credit Facility”). Borrowings under our Credit Facility bear interest at the LIBOR plus an applicable margin or a base rate as defined in the respective credit agreement. Pursuant to the Third A&R Revolving Credit Agreement, among other things:


(a)	the letters of credit sublimit is $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 (the “Financial Covenants”) (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.

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 “Credit Agreement Amendment”).

The Credit Agreement Amendment, among other things:

(a) (i) revised the maximum consolidated total leverage ratio set at 5.5 to 1.0 as of the last day of the fiscal quarter ending each of December 31, 2015, March 31, 2016 and June 30, 2016, (ii) 5.25 to 1.0 as of the last day of the fiscal quarter ending September 30, 2016, and (iv) 5.00 to 1.0 as of the last day of each fiscal quarter thereafter, in each case, without any step-ups in connection with acquisitions;

(b) 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

(c) allows 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. Additionally, we are unable to borrow on our Credit Facility until we have funded the required equity cure for the first quarter of 2016; however, we retain the ability to fund the required equity cure.

Term Loan Agreement

The Term Loan Agreement is a seven-year $450 million senior secured term loan facility. 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 is amortized in equal quarterly installments in an aggregate annual amount equal to 1% of the original principal amount of the initial loan ($1.125 million), with the remainder due on the maturity date.

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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 on the balance sheets. Changes in deferred financing costs are as follows (in thousands):



	2016			2015
Deferred financing costs, January 1	$	14,141		$	16,602
Capitalization of deferred financing costs	86			6
Amortization of deferred financing costs	(762		)	(737		)
Deferred financing costs, March 31	$	13,465		$	15,871

7. 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 currently involved in several such proceedings and disputes, our management believes that none of such proceedings or disputes will have a material adverse effect on our results of operations, cash flows or financial condition. However, future events or circumstances, currently unknown to management, will determine whether the resolution of any litigation or claims ultimately will have a material effect on our results of operations, cash flows or financial condition in any future reporting periods.

Formosa. In March 2013, one of our subsidiaries, Southcross Marketing Company Ltd. (“Marketing”), filed suit against Formosa Hydrocarbons Company, Inc. (“Formosa”) for breach of contract under a gas processing and sales contract between the parties. Formosa filed a counterclaim against Marketing for breach of such contract and a related agreement between the parties. After a bench trial held in January 2015, the judge ruled that Formosa had breached certain of its obligations under the gas processing and sales contract and that Marketing had breached certain of its obligations under such contract and the related agreement. The amount of damages awarded to Marketing was in excess of that awarded to Formosa. The parties agreed upon the allocation of attorneys’ fees with Marketing’s award exceeding that of Formosa. After the ruling, both parties filed motions for reconsideration of certain of the judge’s rulings. A hearing on the motions was held in June 2015 and, on April 20, 2016, the judge rejected Marketing’s motion and granted Formosa’s motion which reduced Marketing’s original award of damages. Despite this, the award of damages to Marketing is still in excess of the damages awarded to Formosa. A judgment is expected to be entered during the second quarter of 2016. The judgment is not expected to have a material impact on our results of operations, cash flows or financial condition.

Regulatory Compliance

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

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Leases

Capital Leases

We have auto leases that are classified as capital leases. The termination dates of the lease agreements vary from 2016 to 2019. We recorded amortization expense related to the capital leases of $0.1 million for the three months ended March 31, 2016 and 2015, respectively. Capital leases entered into during the three months ended March 31, 2016 and 2015 were less than $0.1 million and $0.2 million, respectively. The capital lease obligation amounts included on the balance sheets were as follows (in thousands):



	March 31, 2016		December 31, 2015
Other current liabilities	$	357	$	362
Other non-current liabilities	424		522
Total	$	781	$	884

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 2016 to 2025. Expenses associated with operating leases, recorded in operations and maintenance expenses and general and administrative expenses in our statements of operations, were $0.9 million and $1.2 million for the three months ended March 31, 2016 and 2015, respectively. A rental reimbursement included in our lease agreement associated with the office space we leased in June 2015 of $2.1 million, net of amortization, has been recorded as a deferred liability on our condensed consolidated balance sheets as of March 31, 2016. This amount will continue to be amortized against the lease payments over the length of the lease term.

Purchase Commitments

At March 31, 2016, we had commitments of approximately $5.2 million related primarily to the purchase of pipelines and compressors for our various capital expansion projects. We have other planned capital projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.

8. PARTNERS’ CAPITAL

Ownership

Our units outstanding as of March 31, 2016 are as follows (in units):



	Partners’ Capital
		Owned by Parent
	Public	Holdings	Class B		General
	Common	Common	Convertible	Subordinated	Partner
Units outstanding as of December 31, 2015	21,804,219	6,616,400	15,958,990	12,213,713	1,154,965
Vesting of LTIP units, net	91,398	—	—	—	—
In-kind distributions and issuances to general partner to maintain 2.0% ownership	—	—	—	—	1,866
Units outstanding as of March 31, 2016	21,895,617	6,616,400	15,958,990	12,213,713	1,156,831

Common Units

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

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Class B Convertible Units

The Class B Convertible Units consist of 14,633,000 units plus any additional Class B PIK Units. 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 March 31, 2016, all of our outstanding Class B Convertible Units were indirectly owned by Holdings.

Distribution Rights: The holders of the Class B Convertible Units will receive quarterly distributions in an amount equal to $0.3257 per unit paid in Class B PIK Units (based on a unit issuance price of $18.61) within 45 days after the end of each quarter until converted and as long as certain requirements are met. 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.

With the suspension of distributions to holders of our Class B Convertible Units, such PIK distributions continue to accrue. Distributions on the Class B Convertible Units are cumulative and will be payable in arrears when and if quarterly distributions are approved to be resumed by the board of directors of our General Partner. As of March 31, 2016, we have accumulated, but not yet issued, 563,494 Class B Convertible Units to Holdings and 11,499 general partner units to our General Partner. On May 6, 2016, the board of directors of our General Partner approved the issuance of these units.

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 (a) make a quarterly distribution equal to or greater than $0.44 per common unit, (b) 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 (c) forecast paying a distribution equal to or greater than $0.44 per unit from forecasted Class B Distributable Cash Flow on all outstanding common units for the two quarters immediately following the measurement period.

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

Subordinated Units

Subordinated units represent limited partner interests in us and convert to common units at the end of the Subordination Period (as defined in our Partnership Agreement). The principal difference between our common units and our subordinated units is that in any quarter during the Subordination Period, holders of the subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units do not accrue arrearages. Beginning with the third quarter of 2014, until such time we have a Distributable Cash Flow Ratio of at least 1.0, Holdings, the indirect holder of the subordinated units has waived the right to receive distributions on any subordinated units that would cause the Distributable Cash Flow Ratio to be less than 1.0. In addition, the Credit Agreement Amendment imposed additional restrictions on our ability to declare and pay quarterly cash distributions with respect to our subordinated units. See Note 6.

General Partner Interests

As defined by 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. In connection with the 8,029,729 common units issued to Holdings on April 29, 2016, our General Partner made a capital contribution in exchange for additional general partner units to maintain its 2.0% ownership interest in us.

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9. TRANSACTIONS WITH RELATED PARTIES

Affiliated Directors

Effective April 13, 2016, the board of directors of our General Partner includes one director affiliated with EIG, one director affiliated with Tailwater and four outside directors. Pursuant to the terms of the POR, the Lenders have the right to appoint two additional directors (one of which must be independent). The eighth member of the board of directors of our General Partner, and its chairman, is David W. Biegler. Mr. Biegler will serve as chairman until the earlier of August 4, 2016 and his death or resignation. 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 March 31,
	2016		2015
Charlesbank Capital Partners, LLC⁽¹⁾	$	66	$	14
EIG	26		16
Tailwater	29		16
Total fees and expenses paid for director services to affiliated entities	$	121	$	46

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

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 March 31,
	2016		2015
Reimbursements included in general and administrative expenses	$	3,496	$	3,134
Reimbursements included in operations and maintenance expenses	5,298		4,781
Total reimbursements to our General Partner and its affiliates	$	8,794	$	7,915

Compensation expense for services incurred by us on behalf of Southcross Energy LLC was billed to Southcross Energy LLC for the three months ended March 31, 2015. Compensation expense not incurred on our behalf of $0.1 million was billed to Southcross Energy LLC.

Other Transactions with Affiliates

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

In addition, each of these executives of our General Partner will receive a one-time retention bonus in an amount equal to 100% of then-current annual salary if the executive remains continuously employed with our General Partner through November 1, 2016. We have recorded $0.3 million in general and administrative expenses for our allocable share of costs for the three months ended March 31, 2016.

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.

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In conjunction with the 2015 Holdings Acquisition, we entered into 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 has been capped at $1.7 million per quarter. In the first quarter of 2016, we exceeded this cap by $1.0 million which was recorded as a receivable from Holdings on our condensed consolidated balance sheets.

The Partnership recorded revenues from affiliates of $24.3 million and $7.4 million for the three months ended March 31, 2016 and 2015, respectively, in accordance with the G&P Agreement, the NGL Agreement and the commercial agreements entered into in connection with the 2015 Holdings Acquisition.

We had accounts receivable due from affiliates of $51.9 million and $49.7 million as of March 31, 2016 and December 31, 2015, respectively, and accounts payable due to affiliates of $10.8 million and $7.9 million as of March 31, 2016 and December 31, 2015, respectively. The affiliate receivable and payable balances are related primarily to transactions associated with Holdings, noted above, and our joint venture investments (defined in Note 12). The receivable balance due from Holdings was brought current on April 13, 2016 through a payment of $39.1 million.

10. INCENTIVE COMPENSATION

Unit Based Compensation

Long-Term Incentive Plan

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

On November 9, 2015, the holders of a majority of our limited partnership units 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 was also 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, 2015	687,920		$	15.56
Granted units	47,500		$	11.82
Forfeited units	(19,024	)	$	18.79
Units recaptured for tax withholdings	(40,979	)	$	8.41
Vested units	(91,398	)	$	13.02
Unvested - March 31, 2016	584,019		$	14.89

For the three months ended March 31, 2016, we granted awards under the LTIP with a grant date fair value of $0.2 million which we have classified as equity awards. As of March 31, 2016, we had total unamortized compensation expense of $6.5 million related to unvested awards. Compensation expense associated with awards granted on March 10, 2015 of 84,423 units was recognized over a one-year vesting period, while compensation expense for the remaining awards is expected to be recognized over the three-year vesting period from each equity award’s grant date. As of March 31, 2016, we had 5,070,576 units available for issuance under the LTIP.

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Unit Based Compensation Expense

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



	Three Months Ended March 31,
	2016		2015
Unit-based compensation	$	981	$	813

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 $18,000 annually for the period. The following table summarizes information regarding contributions and the expense recognized for the matching contributions, which is included in general and administrative expense on our statements of operations (in thousands):



	Three Months Ended March 31,
	2016		2015
Matching contributions expensed for employee savings plan	$	209	$	181

11. REVENUES

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



	Three Months Ended March 31,
	2016		2015
Sales of natural gas	$	62,603	$	112,786
Sales of NGLs and condensate	26,189		37,183
Transportation, gathering and processing fees	29,135		35,053
Other	1,799		916
Total revenues	$	119,726	$	185,938

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12. INVESTMENTS IN JOINT VENTURES

We own equity interests in three joint ventures with Targa Pipeline Partners LP as our joint venture partner. T2 Eagle Ford Gathering Company LLC (“T2 Eagle Ford”), T2 LaSalle Gathering Company LLC (“T2 LaSalle”) and T2 EF Cogeneration Holdings LLC (“T2 Cogen”) operate pipelines and a cogeneration facility located in South Texas. We indirectly own a 50% interest in T2 Eagle Ford, a 50% interest in T2 Cogen and a 25% interest in T2 LaSalle. 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. The joint ventures’ summarized financial data from their statements of operations for the three months ended March 31, 2016 and 2015 is as follows (in thousands):



	Three Months Ended March 31,
	2016			2015
Revenue
T2 Eagle Ford	$	1,402		$	921
T2 Cogen	922			1,662
T2 LaSalle	380			379

Net loss
T2 Eagle Ford	$	(4,586	)	$	(4,997	)
T2 Cogen	(1,542		)	(1,361		)
T2 LaSalle	(1,468		)	(1,520		)

Our equity in losses of joint venture investments is comprised of the following for the three months ended March 31, 2016 and 2015 (in thousands):



	Three Months Ended March 31,
	2016			2015
T2 Eagle Ford	$	(2,291	)	$	(2,491	)
T2 Cogen	(771		)	(681		)
T2 LaSalle	(367		)	(380		)
Equity in losses of joint venture investments	$	(3,429	)	$	(3,552	)

Our investments in joint ventures is comprised of the following as of March 31, 2016 and December 31, 2015 (in thousands):



	March 31, 2016		December 31, 2015
T2 Eagle Ford	$	108,620	$	105,755
T2 Cogen	15,584		16,747
T2 LaSalle	17,576		18,024
Investments in joint ventures	$	141,780	$	140,526

13. CONCENTRATION OF CREDIT RISK

Our primary markets are in South Texas, Alabama and Mississippi. We have a concentration of revenues and trade accounts receivable due from customers engaged in the production, trading, distribution and marketing of natural gas and NGL products. These concentrations of customers may affect overall credit risk in that these customers may be affected similarly by changes in economic, regulatory or other factors. We analyze our customers’ historical financial and operational information before extending credit.

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Our top ten customers for the three months ended March 31, 2016 and 2015 represent the following percentages of consolidated revenue:



	Three Months Ended March 31,
	2016		2015
Top ten customers	63.3	%	60.1	%

The percentage of total consolidated revenue for each customer that exceeded 10% of total revenues for the three months ended March 31, 2016 and 2015 was as follows:



	Three Months Ended March 31,
	2016		2015
Texstar Midstream^(b)	12.6	%	(a)
Trafigura AG	(a)		10.9	%

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

(b) TexStar Midstream is an indirectly wholly-owned subsidiary of Holdings.

For the three months ended March 31, 2016 and 2015, we did not experience significant non-payment for services. As of March 31, 2016 and December 31, 2015, we have an allowance for uncollectible accounts receivable of $0.1 million.

14. SUPPLEMENTAL INFORMATION

Supplemental Cash Flow Information (in thousands)



	Three Months Ended March 31,
	2016			2015
Supplemental Disclosures:
Cash paid for interest, net of amounts capitalized	$	8,046		$	6,841
Cash received for tax refunds	(55		)	—
Supplemental disclosures of non-cash investing and financing activities:
Accounts payable related to capital expenditures	5,477			22,793
Capital lease obligations	—			207
Accrued distribution equivalent rights on LTIP units	10			342
Class B Convertible unit in-kind distributions	—			3,712
Valley Wells' operating expense cap adjustment	991			—

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 March 31,
	2016			2015
Total interest costs	$	9,528		$	7,800
Capitalized interest included in property, plant and equipment, net	(358		)	(302		)
Interest expense	$	9,170		$	7,498

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 March 31, 2016 were as follows: $4.2 million for the remainder of 2016; $5.6 million in 2017; $2.2 million in 2018; $2.2 million in 2019; $2.2 million in 2020 and

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$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 for the three months ended March 31, 2016 and 2015, respectively, and have been included within transportation, gathering and processing fees within Note 11. These amounts do not include variable fees based on the actual gas volumes delivered under the contracts. Variable fees recognized in revenues within transportation, gathering and processing fees within Note 11 were $0.8 million for the three months ended March 31, 2016 and 2015, respectively. Deferred revenue associated with these agreements was $6.0 million and $5.3 million at March 31, 2016 and December 31, 2015, 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 report 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 2015 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 report 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 material reduction in exploration, development and production of crude oil or natural gas;


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


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


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


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


•	the financial condition and creditworthiness of our customers;


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


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


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


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


•	our ability to consummate acquisitions, successfully integrate the acquired businesses and realize anticipated cost savings and other synergies from any acquisitions, including with respect to our acquisition of certain gathering and processing assets from TexStar Midstream Services, LP in August 2014 and other assets acquired in May 2015;


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


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


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


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


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


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


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


•	the effects of laws and governmental regulations and policies;


•	the effects of existing and future litigation;


•	the impact on our financial condition and operations resulting from the financial condition and operations of our controlling unitholder, Southcross Holdings LP;


•	changes in general economic conditions;


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


•	the financial health of our controlling unitholder, Southcross Holdings LP, and its ability to pay amounts owed to us on a timely basis.

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

The foregoing list of risks and uncertainties may not contain all of the risks and uncertainties that could affect us. In addition, in light of these risks and uncertainties, the matters referred to in the forward-looking statements contained in this report may not, in fact, occur. Accordingly, undue reliance should not be placed on these statements. We undertake no obligation to 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

Recent Developments

Holdings Chapter 11 Reorganization

Liquidity Consideration

As of March 31, 2016, we were not in compliance with the consolidated total leverage ratio of our Financial Covenants (as defined in Note 6 to our condensed consolidated financial statements) absent an equity cure of $0.5 million within approximately 15 days following the issuance of these financial statements. On March 17, 2016, we entered into an equity cure contribution agreement (the “Equity Cure Agreement”, discussed below) with Holdings whereby we have the right to cure any default with respect to our Financial Covenants by having Holdings purchase equity interests in or make capital contributions to us, in an aggregate amount of up to $50 million. We believe that we will have the ability to fund this equity cure through the Equity Cure Agreement. On March 30, 2016, we received $11.9 million from Holdings in exchange for 8,029,729 common units, pursuant to the terms of the Equity Cure Agreement, to fund a portion of the balance of the equity cure required to comply with the consolidated total leverage ratio of our Financial Covenants as of December 31, 2015. In addition, our forecast indicates future shortfalls in the amount of consolidated EBITDA necessary to remain in compliance with the consolidated total

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leverage ratio of our Financial Covenants in our Credit Facility (defined below) for the remainder of 2016. We will have the remaining amount from the Equity Cure Agreement available to fund additional equity cures through the fourth quarter of 2016, as needed, and to assist in the Partnership's ability to continue as a going concern for a reasonable period of time. We believe that this amount will be sufficient to fund any equity cure requirements during this period. For additional details regarding this equity cure and the Equity Cure Agreement, see below and Note 1 to our condensed consolidated financial statements.

Distribution Suspension

Our Operations

Our integrated operations provide a full range of complementary services extending from wellhead to market, including gathering natural gas at the wellhead, treating natural gas to meet downstream pipeline and customer quality standards, processing natural gas to separate NGLs from natural gas, fractionating NGLs into the various components and selling or delivering pipeline quality natural gas, Y-grade and purity product NGLs to various industrial and energy markets as well as large pipeline systems. Through our network of pipelines, we connect supplies of natural gas to our customers, which include industrial, commercial and power generation customers and local distribution companies. All of our operations are managed as and presented in one reportable segment.

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


•	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 are generally combined with fixed-fee and fixed-spread arrangements for processing services and, therefore, represent only a portion of a processing contract's value. The revenues we receive from these arrangements directly correlate with fluctuating general commodity price levels of natural gas and NGLs and the volume of NGLs recovered relative to the fixed recovery obligations.

We assess gross operating margin opportunities across our integrated value stream so that processing margins may be supplemented by gathering and transportation fees and opportunities to sell residue gas and NGLs at fixed-spreads. Gross operating margin earned under fixed-fee and fixed-spread arrangements is 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

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commodity prices could result in a decline in volumes entering our system and, thus, a decrease in gross operating margin for our fixed-fee and fixed-spread arrangements.

The following table summarizes our gross operating margins from these arrangements (in thousands):



	Three Months Ended March 31,
	2016						2015
	Gross Operating Margin			%			Gross Operating Margin		%
Fixed-fee	$	30,814	⁽¹⁾	76.5	%	⁽¹⁾	$	35,605	79.5	%
Fixed-spread	5,146			12.8	%		4,134		9.2	%
Sub-total	35,960			89.3	%		39,739		88.7	%
Commodity-sensitive	4,319			10.7	%		5,084		11.3	%
Total gross operating margin	$	40,279		100.0	%		$	44,823	100.0	%

(1) Fixed-fee gross operating margin and gross operating margin percentage for the three months ended 2016 include an increase in activity under our gathering, transportation and other services agreements with Holdings, which have increased fee-based revenue with no associated cost of natural gas or liquids sold.

How We Evaluate Our Operations

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

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

Gross Operating Margin — Gross operating margin of our contracts is one of the metrics we use to measure and evaluate our performance. Gross operating margin is not a measure calculated in accordance with accounting principles generally accepted in the United States of America (“GAAP”). We define gross operating margin as the sum of revenues less the cost of natural gas and NGLs sold. For our fixed-fee contracts, we record the fee as revenue and there is no offsetting cost of natural gas and NGLs sold. For our fixed-spread and commodity-sensitive arrangements, we record as revenue all of our proceeds from the sale of the natural gas and NGLs and record as an expense the associated cost of natural gas and NGLs sold. For our gathering, transportation and other services agreements with Holdings (discussed in Note 9 to the condensed consolidated financial statements), fee-based revenue increases with no associated cost of natural gas or liquids sold.

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

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

We define Adjusted EBITDA as net income/loss, plus interest expense, income tax expense, depreciation and amortization expense, equity in losses of joint venture investments, certain non-cash charges (such as non-cash unit-based compensation, impairments, loss on extinguishment of debt and unrealized losses on derivative contracts), major litigation costs net of recoveries, transaction-related costs, revenue deferral adjustment, loss on sale of assets and selected charges that are unusual or non-recurring; less interest income, income tax benefit, unrealized gains on derivative contracts, equity in earnings of joint

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venture investments and selected gains that are unusual or non-recurring. Adjusted EBITDA should not be considered an alternative to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP.

Adjusted EBITDA is used as a supplemental measure by our management and by external users of these financial statements, such as investors, commercial banks, research analysts and others, to assess:


•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;


•	the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions;


•	operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and


•	the attractiveness of capital projects and acquisitions and the overall rates of return on investment opportunities.

We define distributable cash flow as Adjusted EBITDA, plus interest income and income tax benefit, less cash paid for interest (net of capitalized costs), income tax expense and maintenance capital expenditures. We use distributable cash flow to analyze our performance and liquidity. Distributable cash flow does not reflect changes in working capital balances.

Distributable cash flow is used to assess:


•	the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders; and


•	the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

Non-GAAP Financial Measures

Gross operating margin, Adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures provides useful information to investors in assessing our financial condition, results of operations and cash flows from operations. Net income is the GAAP measure most directly comparable to each of gross operating margin and Adjusted EBITDA. The GAAP measure most directly comparable to distributable cash flow is net cash provided by operating activities. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as an analytical tool because each excludes some but not all items that affect the most directly comparable GAAP financial measure. You should not consider any of gross operating margin, Adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross operating margin, Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

Reconciliations of Non-GAAP Financial Measures

The following table presents a reconciliation of gross operating margin to net loss (in thousands):



	Three Months Ended March 31,
	2016			2015
Reconciliation of gross operating margin to net loss:
Gross operating margin	$	40,279		$	44,823
Add (Deduct):
Income tax benefit (expense)	5			(69		)
Equity in losses of joint venture investments	(3,429		)	(3,552		)
Interest expense	(9,170		)	(7,498		)
Loss on sale of assets, net	—			(218		)
General and administrative	(7,886		)	(7,805		)
Depreciation and amortization	(18,541		)	(17,031		)
Operations and maintenance	(16,778		)	(22,555		)
Net loss	$	(15,520	)	$	(13,905	)

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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 March 31,
	2016			2015
Net cash provided by operating activities	$	(17,172	)	$	2,048
Add (deduct):
Depreciation and amortization	(18,541		)	(17,031		)
Unit-based compensation	(981		)	(813		)
Amortization of deferred financing costs and PIK interest	(1,073		)	(825		)
Loss on sale of assets, net	—			(218		)
Unrealized loss on financial instruments	(30		)	(167		)
Equity in losses of joint venture investments	(3,429		)	(3,552		)
Distribution from joint venture investment	(390		)	—
Other, net	121			(11		)
Changes in operating assets and liabilities:
Trade accounts receivable, including affiliates	(9,099		)	(18,307		)
Prepaid expenses and other current assets	(1,173		)	297
Other non-current assets	280			(170		)
Accounts payable and accrued expenses	18,663			27,140
Deposits paid to suppliers	15,300			—
Other liabilities, including affiliates	2,004			(2,296		)
Net loss	$	(15,520	)	$	(13,905	)
Add (deduct):
Depreciation and amortization	$	18,541		$	17,031
Interest expense	9,170			7,498
Income tax (benefit) expense	(5		)	69
Unrealized loss on commodity swaps	—			111
Loss on sale of assets, net	—			218
Revenue deferral adjustment	754			754
Unit-based compensation	981			813
Major litigation costs, net of recoveries	125			453
Transaction-related costs	6			301
Equity in losses of joint venture investments	3,429			3,552
Retention bonus due from Holdings	898			—
Valley Wells' operating expense cap adjustment	991			—
Fees related to Equity Cure Agreement	510			—
Investment distribution from joint venture	390			—
Other, net	426			87
Adjusted EBITDA	$	20,696		$	16,982
Cash interest, net of capitalized costs	(8,046		)	(6,636		)
Income tax benefit (expense)	5			(69		)
Maintenance capital expenditures	(2,331		)	(2,527		)
Distributable cash flow	$	10,324		$	7,750

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Results of Operations

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



	Three Months Ended March 31,
	2016			2015
Revenues:
Revenues	$	95,455		$	178,491
Revenues - affiliates	24,271			7,447
Total revenues	119,726			185,938
Expenses:
Cost of natural gas and liquids sold	79,447			141,115
Operations and maintenance	16,778			22,555
Depreciation and amortization	18,541			17,031
General and administrative	7,886			7,805
Loss on sale of assets, net	—			218
Total expenses	122,652			188,724

Loss from operations	(2,926		)	(2,786		)
Other expense:
Equity in losses of joint venture investments	(3,429		)	(3,552		)
Interest expense	(9,170		)	(7,498		)
Total other expense	(12,599		)	(11,050		)
Loss before income tax benefit (expense)	(15,525		)	(13,836		)
Income tax benefit (expense)	5			(69		)
Net loss	$	(15,520	)	$	(13,905	)

Other financial data:
Adjusted EBITDA	$	20,696		$	16,982
Gross operating margin	$	40,279		$	44,823

Maintenance capital expenditures	$	2,331		$	2,527
Growth capital expenditures	$	3,143		$	38,475

Operating data:
Average volume of processed gas (MMcf/d)	343			447
Average volume of NGLs produced (Bbls/d)	39,651			41,880

Realized prices on natural gas volumes ($/Mcf)	$	1.87		$	2.92
Realized prices on NGL volumes ($/gal)	0.27			0.41

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Three Months Ended March 31, 2016 Compared to Three Months Ended March 31, 2015

Volume and overview. Processed gas volumes decreased 104 MMcf/d, or 23%, to 343 MMcf/d during the three months ended March 31, 2016, compared to 447 MMcf/d during the three months ended March 31, 2015. This decrease was due primarily to an outage at Holdings’ Lancaster gas treating facility due to a fire in February 2016, as well as a continued low commodity price environment for natural gas, crude oil and NGLs resulting in certain customers redirecting their gas away from our processing facilities.

NGLs produced at our processing plants for the three months ended March 31, 2016 averaged 39,651 Bbls/d, a decrease of 5%, or 2,229 Bbls/d, compared to 41,880 Bbls/d for the three months ended March 31, 2015. The decrease in NGLs produced is due primarily to an outage at Holdings’ Lancaster gas treating facility due to a fire in February 2016, as well as certain customers redirecting their gas away from our processing facilities.

Gross operating margin for the three months ended March 31, 2016 was $40.3 million, compared to $44.8 million for the three months ended March 31, 2015. This decrease of $4.5 million, or 10%, was due primarily to decreased processed gas volumes and NGLs produced.

Adjusted EBITDA increased by $3.7 million, or 22%, to $20.7 million for the three months ended March 31, 2016, compared to $17.0 million for the three months ended March 31, 2015, due primarily to decreased operations and maintenance expenses as we continue to implement cost savings initiatives. We had a net loss of $15.5 million for the three months ended March 31, 2016 compared to a net loss of $13.9 million for the three months ended March 31, 2015. Net loss increased by $1.6 million primarily due to decreased gross operating margin, additional depreciation and amortization expense and increased interest expense from higher average borrowings, partially offset by decreased operations and maintenance expenses.

Revenues. Our total revenues for the three months ended March 31, 2016 decreased $66.2 million, or 36%, to $119.7 million compared to $185.9 million for the three months ended March 31, 2015. This decrease was due primarily to a decrease in realized prices in natural gas and NGLs, as well as a decrease in processed gas volumes resulting in revenue from sales of natural gas decreasing by $50.2 million and revenue from sales of NGLs and condensate decreasing by $11.0 million for the three months ended March 31, 2016 compared to the three months ended March 31, 2015.

Cost of natural gas and NGLs sold. Our cost of natural gas and NGLs sold for the three months ended March 31, 2016 was $79.4 million, compared to $141.1 million for the three months ended March 31, 2015. This decrease of $61.7 million, or 44%, was due primarily to lower processed gas volumes and lower natural gas and NGL prices compared to the same period in 2015.

Operations and maintenance expenses. Operations and maintenance expenses for the three months ended March 31, 2016 were $16.8 million, compared to $22.6 million for the three months ended March 31, 2015. This decrease of $5.8 million, or 26%, was due primarily to lower plant and pipeline operating expenses as we implemented cost saving initiatives.

General and administrative expenses. General and administrative expenses for the three months ended March 31, 2016 were $7.9 million, compared to $7.8 million for the three months ended March 31, 2015 for an increase of $0.1 million, or 1%.

Depreciation and amortization expense. Depreciation and amortization expense for the three months ended March 31, 2016 was $18.5 million, compared to $17.0 million for the three months ended March 31, 2015. The increase of $1.5 million, or 9%, was due primarily to the depreciation of capital projects placed in service in the second half of 2015.

Equity in losses of joint venture investments. Our share of losses incurred by the joint venture investments was $3.4 million for the three months ended March 31, 2016 compared to $3.6 million for the three months ended March 31, 2015, for a decrease of $0.2 million, or 6%. 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 primarily related to the joint ventures’ depreciation and amortization.

Interest expense. For the three months ended March 31, 2016, interest expense was $9.2 million, compared to $7.5 million for the three months ended March 31, 2015. This increase of $1.7 million was due primarily to higher average borrowings and higher interest rates on borrowings.

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Liquidity and Capital Resources

Sources of Liquidity

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

We expect to fund short term cash requirements, such as operating and maintenance and general and administrative expenses and maintenance capital expenditures, primarily through operating cash flows. We expect to fund long-term cash requirements, such as for expansion projects and acquisitions, through several sources, including operating cash flows, borrowings under our Senior Credit Facilities and issuances of additional debt and equity securities, as appropriate and subject to market conditions. See Note 6 to our condensed consolidated financial statements.

After considering these uncertainties, our forecast indicates future shortfalls in the amount of consolidated EBITDA (as defined in the Third Amended and Restated Revolving Credit Agreement with Wilmington Trust, National Association, UBS Securities LLC and Barclays Bank PLC and a syndicate of lenders (the “Third A&R Revolving Credit Agreement”), as amended in May 2015) necessary to remain in compliance with the consolidated total leverage ratio of our Financial Covenants (as defined in Note 6 to our condensed consolidated financial statements) in our Credit Facility (defined below) for the remainder of 2016. As discussed in further detail in Note 6 to our condensed consolidated financial statements, we have the right to cure such a Financial Covenant Default (as defined in Note 6 to our condensed consolidated financial statements) by either our Sponsors or Holdings purchasing equity interests in or making capital contributions (an equity cure) resulting in, among other things, proceeds that, if added to consolidated EBITDA, would result in us satisfying the Financial Covenants. Once such an equity cure is made, it is included in our consolidated EBITDA calculation in any rolling twelve month period that includes the quarter that was cured. Should there be an event of default under the Credit Facility, and such default is not cured, we also would experience a cross default under our Term Loan Agreement (defined in Note 6 to our condensed consolidated financial statements) and all of our debt would become due and payable to our lenders.

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The number of units to be issued to Holdings in exchange for this contribution has yet to be determined since the required number of days to calculate the VWAP has not been reached as of the date of the issuance of these financial statements.

As of May 5, 2016, we had $615.0 million in outstanding borrowings under our Senior Credit Facilities. Under our five-year revolving credit facility, pursuant to our Third A&R Revolving Credit Agreement, we have the ability to borrow up to $200 million (the “Credit Facility”) less any letters of credit amounts outstanding, which as of May 5, 2016 provided us access to $10.8 million. However, we are unable to borrow on our Credit Facility until we have funded the required equity cure for the first quarter of 2016 with the available funding options described above.

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 March 31,
	2016		2015
Maintenance capital	$	2,331	$	2,527
Growth capital	3,143		38,475
Capital expenditures	$	5,474	$	41,002

Our growth capital expenditures during the three months ended March 31, 2016 relate primarily to various expansion and improvement projects primarily in our South Texas assets. The growth capital expenditures during the three months ended March 31, 2015 related primarily to the construction of the Valley Wells sour gas gathering and treating system and the compression assets that are part of the Valley Wells and Lancaster gathering and treating systems, and the timing of payments, $9.7 million of which related to 2014 activity but were paid in 2015, as well as various expansion and improvement projects primarily in our South Texas assets.

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

Our ability to benefit from growth projects to accommodate 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 experienced declining volumes over a sustained period and/or unfavorable commodity prices.

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We believe that cash from operations, cash on hand and the sale of equity to Holdings under the Contribution Amount will provide sufficient liquidity to meet future short-term capital requirements for a reasonable period of time. The sufficiency of these liquidity sources to fund necessary and committed capital needs will be dependent upon our ability to meet our covenant requirements of our Senior Credit Facilities. We believe we have and will continue to have sufficient liquidity to operate our business. See Notes 1 and 6 to our condensed consolidated financial statements.

Growth projects and acquisitions are key elements of our business strategy. We intend to finance our growth capital primarily through the issuance of debt and equity. 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 over the longer term will depend on our future operating performance, financial condition and credit rating and, more broadly, on the availability of equity and 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):



	Three Months Ended March 31,
	2016			2015
Net cash provided by (used in) operating activities	$	(17,172	)	$	2,048
Net cash used in investing activities	(10,421		)	(38,438		)
Net cash provided by financing activities	29,020			34,971

Operating cash flows — Net cash used in operating activities was $17.2 million for the three months ended March 31, 2016, compared to net cash provided by operating activities of $2.0 million for the three months ended March 31, 2015. The decrease in cash from operating activities of $19.2 million primarily was the result of deposits paid to suppliers of $15.3 million during the three months ended March 31, 2016 compared to the three months ended March 31, 2015. We expect these deposits to be repaid to us in full in exchange for letters of credit to our suppliers in the second quarter of 2016.

Investing cash flows — Net cash used in investing activities for the three months ended March 31, 2016 was $10.4 million, compared to $38.4 million for the three months ended March 31, 2015. The decrease of $28.0 million primarily relates to decreased capital expenditures during the three months ended March 31, 2016 compared to the three months ended March 31, 2015.

Financing cash flows — Net cash provided by financing activities for the three months ended March 31, 2016 was $29.0 million, compared to $35.0 million for the three months ended March 31, 2015. The decrease was due to reduced net borrowings of $32.1 million from our debt instruments, partially offset by $14 million received from issuance of the PIK Notes and $11.9 million for the fourth quarter 2015 equity cure provided by Holdings to us during the three months ended March 31, 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 under Part I, Item 1 of this report.

Critical Accounting Policies and Estimates

Our critical accounting policies are consistent with those described in our 2015 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 2015 Annual Report on Form 10-K and there have been no material changes in those exposures from December 31, 2015 to March 31, 2016.

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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 first quarter of 2016 that have materially affected or are reasonably likely to materially affect, 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 7 to our condensed consolidated financial statements.

Item 1A. Risk Factors.

Our Risk Factors are consistent with those disclosed in Part I, Item 1A Risk Factors of our 2015 Annual Report on Form 10-K.

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

None.

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:	May 10, 2016	By:	/s/ Bret M. Allan
			Bret M. Allan
			Senior Vice President and Chief Financial Officer
			(Principal Financial Officer)

Date:	May 10, 2016	By:	/s/ G. Tracy Owens
			G. Tracy Owens
			Vice President and Chief Accounting Officer
			(Principal Accounting Officer)

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		EXHIBIT INDEX
Exhibit
Number		Description
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 (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).
4.1		Registration Rights Agreement, dated as of April 12, 2013, by and between Southcross Energy Partners, L.P. and Southcross Energy LLC (incorporated by reference to Exhibit 4.1 to our Annual Report on Form 10-K for the fiscal year ending December 31, 2012).
10.1		Equity Cure Contribution Agreement, dated March 17, 2016, by and between Southcross Energy Partners GP, LLC and Southcross Holdings LP (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated March 22, 2016.
10.2#		Retention Agreement, dated March 17, 2016, by and between Southcross Energy GP, LLC and Mr. John E. Bonn (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K dated March 22, 2016).
10.3#		Retention Agreement, dated March 17, 2016, by and between Southcross Energy GP, LLC and Mr. Bret M. Allan (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K dated March 22, 2016).
10.4#		Retention Agreement, dated March 17, 2016, by and between Southcross Energy GP, LLC and Mr. Joel D. Moxley (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K dated March 22, 2016).
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.

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