Southcross Energy Partners 10-Q 2013 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2013

OR

oTRANSITION 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.)
1700 Pacific Avenue, Suite 2900 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 x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark 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 o
Non-accelerated filer x (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 x

Indicate the number of units outstanding of the issuer’s classes of common units, subordinated units and series A convertible preferred units, as of the latest practicable date:

As of May 6, 2013, the registrant has 12,219,699 common units outstanding, 12,213,713 subordinated units outstanding and 1,466,325 series A convertible preferred units outstanding.  Our common units trade on the NYSE under the symbol “SXE.”

Commonly Used Terms

As generally used in the energy industry and in this Quarterly Report on Form 10-Q, the following terms have the following meanings:

/d: Per day

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

Mgal: One thousand gallons

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 or NGLs transported or passing through a pipeline, plant, terminal or other facility

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

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FORM 10-Q

TABLE OF CONTENTS

Southcross Energy Partners, L.P.

PART I — FINANCIAL INFORMATION		5
ITEM 1.	Financial Statements (Unaudited)	5
	Condensed Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012	5
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2013 and 2012	6
	Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2013 and 2012	7
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2013 and 2012	8
	Condensed Consolidated Statements of Changes in Partners’ Capital and Members’ Equity for the Three Months Ended March 31, 2013 and 2012	9
	Notes to Condensed Consolidated Financial Statements	10
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	35
ITEM 4.	Controls and Procedures	36
PART II — OTHER INFORMATION		37
ITEM 1.	Legal Proceedings	37
ITEM 1A.	Risk Factors	37
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37
ITEM 3.	Defaults Upon Senior Securities	37
ITEM 4.	Mine and Safety Disclosures	37
ITEM 5.	Other Information	37
ITEM 6.	Exhibits	38
SIGNATURES		39

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FORWARD-LOOKING INFORMATION

Investors are cautioned that certain statements contained in this Quarterly Report on Form 10-Q as well as in periodic press releases and oral statements made by our management team during our presentations are “forward-looking” statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will continue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would,” and “could.” In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us or our subsidiaries, are also forward-looking statements. These forward-looking statements involve external risks and uncertainties, including, but not limited to, those described under the section entitled “Risk Factors” included herein and in our 2012 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 Quarterly Report on Form 10-Q and subsequent written and oral forward-looking statements attributable to us, or to persons acting on our behalf, are expressly qualified in their entirety by these risks and uncertainties. These risks and uncertainties include, among others:

·the volatility of natural gas, crude oil and NGL prices and the price and demand of products derived from these commodities;

·competitive conditions in our industry and the extent and success of producers 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 non-performance by third parties, including suppliers, contractors, operators, processors, transporters and customers;

·our ability to effectively recover NGLs 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, integrate the acquired businesses successfully, realize anticipated cost savings and other synergies from any acquisitions;

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

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

·our access to financing and ability to remain in compliance with our financing covenants;

·our ability to generate sufficient operating cash flow to fund our minimum quarterly distribution;

·changes in general economic conditions;

·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 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; and

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

Developments in any of these areas could cause actual results to differ materially from those anticipated or projected; or affect our ability to maintain distribution levels; 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 Quarterly Report on Form 10-Q may not, in fact, occur. Accordingly, undue reliance should not be placed on these statements. We undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as otherwise required by law.

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PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

SOUTHCROSS ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except for unit data)

(Unaudited)

	March 31, 2013			December 31, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	2,250		$	7,490
Trade accounts receivable	42,346			50,994
Prepaid expenses	1,169			1,762
Other current assets	3,220			1,001
Total current assets	48,985			61,247
Property, plant and equipment, net	569,575			550,603
Intangible assets, net	1,610			1,624
Other assets	5,479			5,131
Total assets	$	625,649		$	618,605
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	62,164		$	96,801
Other current liabilities	2,400			3,586
Total current liabilities	64,564			100,387
Long-term debt	246,000			191,000
Other non-current liabilities	695			751
Total liabilities	311,259			292,138
Commitments and contingencies (Note 9)
Partners’ capital:
Common units - (12,213,713 units issued and outstanding as of March 31, 2013 and December 31, 2012)	188,569			194,365
Subordinated units - (12,213,713 units issued and outstanding as of March 31, 2013 and December 31, 2012)	119,893			125,951
General Partner interest	6,380			6,628
Accumulated other comprehensive loss	(452		)	(477		)
Total partners’ capital	314,390			326,467
Total liabilities and partners’ capital	$	625,649		$	618,605

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,
	2013			2012
Revenues	$	144,250		$	120,617
Expenses:
Cost of natural gas and liquids sold	125,388			99,202
Operations and maintenance	9,889			7,197
Depreciation and amortization	7,249			3,665
General and administrative	6,041			2,433
Total expenses	148,567			112,497
(Loss) income from operations	(4,317		)	8,120
Interest expense	(2,047		)	(1,799		)
(Loss) income before income tax expense	(6,364		)	6,321
Income tax expense	(18		)	(85		)
Net (loss) income	$	(6,382	)	$	6,236
General partner’s interest in net loss	(128		)
Limited partners’ interest in net loss	$	(6,254	)
Less deemed dividend on:
Redeemable preferred units				(742		)
Series B redeemable preferred units				(192		)
Preferred units				(3,746		)
Net income attributable to Southcross Energy LLC common unitholders				$	1,556
Basic and diluted income per unit:
Net loss per limited partner common unit	$	(0.26	)
Net loss per limited partner subordinated unit	$	(0.26	)
Basic net income per Southcross Energy LLC common unit				$	1.28
Diluted net income per Southcross Energy LLC common unit				$	1.07

See accompanying notes.

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SOUTHCROSS ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)

	Three Months Ended March 31,
	2013			2012
Net (loss) income	$	(6,382	)	$	6,236
Other comprehensive income (loss):
Hedging losses reclassified to earnings and recognized in interest expense	94			—
Adjustment in fair value of derivatives	(69		)	—
Total other comprehensive income	25			—
Comprehensive (loss) income	$	(6,357	)	$	6,236

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,
	2013			2012
Cash flows from operating activities:
Net (loss) income	$	(6,382	)	$	6,236
Adjustments to reconcile net (loss) income to net cash (used in) provided by operating activities:
Depreciation and amortization	7,249			3,665
Unit-based compensation	408			—
Deferred financing costs amortization	267			283
Unrealized losses	—			222
Changes in operating assets and liabilities:
Trade accounts receivable	8,648			5,564
Prepaid expenses and other	1,199			668
Other non-current assets	(13		)	(135		)
Accounts payable and accrued expenses	(11,725		)	(9,768		)
Other liabilities	(1,362		)	(2,097		)
Net cash (used in) provided by operating activities	(1,711		)	4,638
Cash flows from investing activities:
Capital expenditures	(49,203		)	(38,912		)
Expenditures related to Gregory facility fire repairs	(2,825		)	—
Net cash used in investing activities	(52,028		)	(38,912		)
Cash flows from financing activities:
Borrowings under our credit agreements	55,000			33,500
Repayments under our credit agreements	—			(4,372		)
Financing costs	(519		)	(2,281		)
Repurchase and retirement of Southcross Energy LLC common units	—			(15,300		)
Proceeds from issuance of Southcross Energy LLC Series B redeemable preferred units	—			35,300
Distribution to partners	(5,982		)	—
Net cash provided by financing activities	48,499			46,847
Net (decrease) increase in cash and cash equivalents	(5,240		)	12,573
Cash and cash equivalents — Beginning of period	7,490			1,412
Cash and cash equivalents — End of period	$	2,250		$	13,985
Supplemental Disclosures:
Cash paid for interest, net of amounts capitalized	$	2,478		$	2,331

See accompanying notes.

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SOUTHCROSS ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN  PARTNERS’ CAPITAL AND MEMBERS’ EQUITY

(In thousands)

(Unaudited)

	Partners’ Capital
	Limited Partners
	Common			Subordinated			General Partner			Accumulated Other Comprehensive Loss			Total
BALANCE - December 31, 2012	$	194,365		$	125,951		$	6,628		$	(477	)	$	326,467
Net loss	(3,127		)	(3,127		)	(128		)	—			(6,382		)
Unit-based compensation	262			—			—			—			262
Distributions paid	(2,931		)	(2,931		)	(120		)	—			(5,982		)
Net effect of cash flow hedges	—			—			—			25			25
BALANCE - March 31, 2013	$	188,569		$	119,893		$	6,380		$	(452	)	$	314,390

	Members’ Equity
	Common Equity			Accumulated Deficit			Total
BALANCE - December 31, 2011	$	1,473		$	(11,638	)	$	(10,165	)
Net income	—			6,236			6,236
Deemed dividend on Redeemable Preferred Units	—			(742		)	(742		)
Deemed dividend on Series B Redeemable Preferred Units	—			(192		)	(192		)
Deemed dividend on Preferred Units	—			(3,746		)	(3,746		)
Repurchase and retirement of common units	(131		)	(15,169		)	(15,300		)
BALANCE - March 31, 2012	$	1,342		$	(25,251	)	$	(23,909	)

See accompanying notes.

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SOUTHCROSS ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1.ORGANIZATION AND DESCRIPTION OF BUSINESS

Organization

Southcross Energy Partners, L.P. (the “Partnership,” “Southcross,” the “Company,” “we,” “our,” or “us”) is a Delaware limited partnership formed in April 2012 to own, operate, develop and acquire midstream energy assets. Our common units are listed on the New York Stock Exchange (“NYSE”) under the symbol “SXE.”

Southcross Energy LLC was formed in 2009 and is the predecessor of the Partnership. In connection with our initial public offering (“IPO”), Southcross Energy LLC contributed all of its operating subsidiaries (its net assets on a historical cost basis), excluding certain liabilities and all preferred units, and became the holding company of the Partnership. Southcross Energy LLC holds all of the equity interests in Southcross Energy Partners GP, LLC, a Delaware limited liability company and our general partner (“General Partner”), as well as all subordinated units and the series A convertible preferred units issued on April 12, 2013 (See Note 11) and 7.5% of the common units of the Partnership.  Southcross Energy LLC is controlled through investment funds and entities associated with Charlesbank Capital Partners, LLC (“Charlesbank”). There was no change in the basis of accounting as a result of the IPO and the contributed net assets of Southcross Energy LLC.

On November 7, 2012, we completed our IPO and after the completion of the IPO and full exercise of the underwriters’ option to purchase additional common units, Southcross Energy LLC’s direct and indirect equity ownership in the Partnership was 58.5%. These condensed consolidated financial statements reflect the assets, liabilities, results of operations and cash flows of the Partnership beginning November 7, 2012 and Southcross Energy LLC for the periods ended prior to November 7, 2012.

See our 2012 Annual Report on Form 10-K for more information related to our organization.

The following table depicts the ownership structure of the Partnership as of March 31, 2013:

Description	Percentage ownership
Public common units	41.5	%
Southcross Energy LLC’s Ownership:
Common units	7.5	%
Subordinated units	49.0	%
General partner interest	2.0	%
Total	100	%

Description of Business

The Partnership is a midstream natural gas company with operations in South Texas, Mississippi and Alabama. We operate as one reportable segment and provide, through our subsidiaries, natural gas gathering, processing, treating, compression and transportation services and NGLs fractionation and transportation services.  The Partnership also sources, purchases, transports and sells natural gas and NGLs.  The Partnership’s network of operations provides a means of connecting our suppliers of natural gas to our customers, which include industrial, commercial and power generation customers and local distribution companies.

2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the Securities and Exchange Commission (“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 with our 2012 Annual Report on Form 10-K. The condensed consolidated financial statements as of March 31, 2013, and for the three months ended March 31, 2013 and 2012, are unaudited and have been prepared on the same basis as the

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annual consolidated financial statements.  All intercompany accounts and transactions have been eliminated in the preparation of the accompanying condensed consolidated financial statements.

In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments, consisting of normal recurring accruals necessary for the fair presentation of the results of operations for the three months ended March 31, 2013 and 2012.  Information for interim periods may not be indicative of our operating results for the entire year. The disclosures included in this Quarterly Report on Form 10-Q provide an update to our 2012 Annual Report on Form 10-K.

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

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 herein.

Significant Accounting Policies

There were no material changes to our significant accounting policies described in Note 2 of our 2012 Annual Report on Form 10-K.

Recent Accounting Pronouncements - Accounting standard-setting organizations frequently issue new or revised accounting rules. We regularly review new pronouncements to determine their impact, if any, on our consolidated financial statements.

In February 2013, the Financial Accounting Standards Board issued an accounting standards update on “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.”  This update requires that we report reclassifications out of accumulated other comprehensive income and their effect on net income by component or financial statement line effective for our quarterly filing for the three months ended March 31, 2013.

The Partnership adopted this standard effective January 1, 2013, which did not have a material impact on our financial statements.

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3. NET INCOME PER LIMITED PARTNER UNIT AND DISTRIBUTIONS

Earnings Per Limited Partner Unit of the Partnership

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, 2013 (in thousands, except unit and per unit data):

	Three Months Ended March 31, 2013
Net loss	$	(6,382	)
General partner’s interest	$	(128	)
Limited partners’ interest:
Common	$	(3,127	)
Subordinated	$	(3,127	)

Three Months Ended March 31, 2013	Common			Subordinated
Interest in net loss	$	(3,127	)	$	(3,127	)
Weighted-average units - basic	12,214			12,214
Effect of diluted units (1)	—			—
Weighted-average units - diluted	12,214			12,214
Basic earnings per unit:
Net loss per unit	$	(0.26	)	$	(0.26	)
Diluted earnings per unit:
Net loss per unit	$	(0.26	)	$	(0.26	)

(1) Because we had a net loss for the three months ended March 31, 2013, the weighted average units outstanding are the same for basic and diluted net loss per common unit. At March 31, 2013, the amount of unvested common units that were not included in the computation of diluted per unit amounts was 140,100.

Distributions

Our Second Amended and Restated Agreement of Limited Partnership (“Partnership Agreement”) requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2012, we distribute all of our Available Cash (as defined in the Partnership Agreement) to unitholders of record (other than holders of Series A Preferred Units (as defined below)) on the applicable record date, as determined by our General Partner.

The following table represents our distribution declared for the quarter ended March 31, 2013 and distribution paid for the quarter ended December 31, 2012 (in thousands, except per unit data):

					Distributions
	Attributable to the	Per Unit			Limited Partners
Payment Date	Quarter Ended	Distribution			Common		Subordinated		General Partner		Total
2013
May 15, 2013	March 31, 2013	$	0.40		$	4,888	$	4,886	$	199	$	9,973
2012
February 14, 2013	December 31, 2012	$	0.24	(1)	$	2,931	$	2,931	$	120	$	5,982

(1) Per unit distribution of $0.24 corresponds to the minimum quarterly distribution of $0.40 per unit, or $1.60 on an annualized basis, pro-rated for the portion of the quarter following the closing of our IPO on November 7, 2012.

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On April 12, 2013, we raised $34.2 million of equity through an issuance of 1,466,325 Series A Convertible Preferred Units (“Series A Preferred Units”) to satisfy the requirements of the second amendment to our $350.0 million senior secured credit facility with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders (“Credit Facility”) (See Note 5 and Note 11). Under the provisions of our Partnership Agreement, we are required to pay the holders of our Series A Preferred Units quarterly distributions of in-kind Series A Preferred Units for the first four full quarters following the issuance of the units and continuing thereafter until we have given notice under the Credit Facility that we have achieved the Target Leverage Ratio (See Note 5) and after the board of directors of our General Partner determines to begin paying quarterly distributions in cash.

Earnings Per Common Unit of Southcross Energy LLC

Southcross Energy LLC calculated earnings per common unit by first deducting the amount of cumulative returns on both the redeemable preferred and preferred units from net income (loss), and dividing this amount by the weighted average number of vested common units (including both the vested Class A common units and Class B units).  For the calculation of diluted earnings per unit, the weighted average unvested units were included in the computation.

The following is a reconciliation of net income per common unit used in the basic and diluted earnings per unit calculations for the three months ended March 31, 2012 (in thousands, except unit and per unit data):

	Three Months Ended March 31, 2012
Net income attributable to Southcross Energy LLC common unitholders	$	1,556
Weighted-average common units outstanding - basic	1,220
Effect of unvested common units	237
Weighted-average common units outstanding-diluted	1,457
Basic earnings per common unit:
Net income per common unit	$	1.28
Diluted earnings per common unit:
Net income per common unit	$	1.07

Southcross Energy LLC calculated earnings per common unit by first deducting the amount of cumulative returns on both Redeemable Preferred and Preferred units from net income (loss), and dividing this amount by the weighted average number of vested common units.  For the calculation of diluted earnings per unit, the unvested units have been included in the computation.  The weighted average number of unvested units that were included in the computation of diluted earnings per unit for the three months ended March 31, 2012 was 237,409 units.  There were no units excluded from out diluted earnings per unit computation as we do not have any anti-dilutive units for the three months ended March 31, 2012.

4. FINANCIAL INSTRUMENTS

Cash and Cash Equivalents, Accounts Receivable and Accounts Payable

As of March 31, 2013 and December 31, 2012, 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.

Credit Facility

The fair value of our Credit Facility executed in 2012 approximates its carrying amount as of March 31, 2013 due primarily to the variable nature of the interest rate of the instrument and given the limited changes in the interest rate environment since its origination on November 7, 2012, which is considered a Level 2 fair value measurement.

Derivatives

Interest Rate Swaps

The Partnership manages its interest rate risk through interest rate swaps.  As of March 31, 2013, the current portion of the interest rate swap liability of $0.5 million was included within other current liabilities, and the non-current portion of the interest rate swap liability of $0.1 million was included within other non-current liabilities.

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The fair value of the interest rate swap liabilities were as follows (in thousands):

	Fair value measurement as of
	March 31, 2013		December 31, 2012
	Significant Other Observable Inputs (Level 2)
	(in thousands)
Interest rate swap liability	$	587	$	638

In March 2012, we terminated an interest rate cap contract and entered into an interest rate swap contract with Wells Fargo, N.A. The interest rate swap has a notional value of $150.0 million, and a maturity date of June 30, 2014. We receive a floating rate based upon one-month LIBOR and pay a fixed rate under the interest rate swap of 0.54%. The interest rate swap is designated as a cash flow hedge for accounting purposes and, thus, to the extent the cash flow hedge is effective, unrealized gains and losses are recorded to accumulated other comprehensive (loss)/income and recognized in interest expense as the underlying hedged transactions (interest payments) are recorded. Any hedge ineffectiveness is recognized in interest expense immediately. The Partnership did not have any hedge ineffectiveness during the period ended March 31, 2013.

Based on current interest rates, the Partnership estimated that approximately $0.5 million of hedging losses related to the interest rate swap contract will be reclassified from accumulated other comprehensive (loss)/income into results of operations within the next 12 months.

The amounts recognized in interest expense associated with derivatives that are not designated as hedging instruments were as follows (in thousands):

	Three Months Ended March 31,
	2013		2012
Unrealized loss on interest rate cap	$	—	$	222
Realized loss on interest rate cap	$	27	$	—

The amounts recognized in interest expense associated with derivatives that are designated as hedging instruments were as follows (in thousands):

	Three Months Ended March 31,
	2013			2012
(Loss) reclassified from accumulated other comprehensive loss to interest expense	$	(94	)	$	—

The change in value recognized in other comprehensive loss on the interest rate swap (effective portion) was as follows (in thousands):

	Three Months Ended March 31,
	2013			2012
Change in value recognized in other comprehensive loss (effective portion)	$	(69	)	$	—

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Commodity Swaps

In its normal course of business, the Partnership periodically enters into month-ahead swap contracts to hedge its exposure to certain intra-month natural gas index pricing risk. There were no outstanding month-ahead swap contracts as of March 31, 2013 or as of December 31, 2012.  The Partnership defines the 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 losses on these derivatives, recognized in revenues in our statements of operations were as follows (in thousands):

	Three Months Ended March 31,
	2013			2012
Realized (loss) on derivatives	$	(46	)	$	(7	)

5. LONG-TERM DEBT

Credit Facility

In connection with the closing of the IPO, the Partnership entered into the Credit Facility and utilized it to fund fees and expenses incurred in connection with the IPO and for the repayment of a portion of Southcross Energy LLC’s debt under its amended and restated credit agreement.

The Partnership may utilize the Credit Facility for working capital requirements and capital expenditures, the purchase of assets, the payment of distributions, the repurchase of units and general purposes of the Partnership. The Credit Facility matures on November 7, 2017, the fifth anniversary of the IPO closing date.

Prior to amending our Credit Facility as discussed below, the Credit Facility included a sublimit of up to $75.0 million for letters of credit of which $25.3 million was outstanding as of March 31, 2013. The Credit Facility also contained various covenants and restrictive provisions and required maintenance of certain financial and operational covenants including but not limited to the following:

·prior to exercising a one-time covenant election (defined by the Credit Facility) in connection with the issuance of certain unsecured notes, a consolidated total leverage ratio (generally defined as debt to EBITDA, as adjusted) of not more than 5.25 to 1.00 with step downs as set forth in the Credit Facility, and a consolidated interest coverage ratio of not less than 2.75 to 1.00. The requirement to maintain a certain consolidated total leverage ratio is subject to a provision for increases to 5.00 to 1.00 in connection with certain future acquisitions; and

·upon exercising a one-time covenant election (defined by the Credit Facility) in connection with the issuance of certain unsecured notes, a consolidated total leverage ratio of not more than 5.25 to 1.00, a consolidated senior secured leverage ratio of not more than 3.50 to 1.00 and a consolidated interest coverage ratio of not less than 2.75 to 1.00.

The Credit Facility also required the Partnership’s Woodsboro gas processing plant and Bonnie View NGL fractionation facility to meet certain initial average daily processing volume requirements by December 31, 2012. Due to required operational ramp up time of the Bonnie View NGL fractionation facility, prior to December 31, 2012, the Partnership requested and received an extension of time to achieve the initial average daily processing volumes to January 31, 2013. The Partnership met the average daily processing volumes necessary to satisfy the Credit Facility’s operational covenants in January 2013. The Partnership is not required to meet these average daily processing volumes on an ongoing basis to be in compliance with the Credit Facility.

Borrowings under the Credit Facility bear interest at LIBOR plus an applicable margin or a base rate as defined in the respective credit agreements. Under the terms of the Credit Facility, the applicable margin under LIBOR borrowings was 3.25% at March 31, 2013. The weighted-average interest rate as of March 31, 2013 was 3.49%.

Our borrowings under the Credit Facility were $246.0 million as of March 31, 2013, and our remaining available capacity under the Amended Credit Facility (as defined below) was $14.0 million as of March 31, 2013. For the three months ended March 31, 2013, our average outstanding borrowings were $229.8 million and our maximum outstanding borrowings were $246.0 million.

As of March 31, 2012, Southcross Energy LLC had an outstanding term loan of $158.9 million with a LIBOR interest rate of 3.25% and two revolver loans, one of $66.5 million with a LIBOR interest rate of 3.25% and the other of $12.0 million with an ABR interest rate of 5.25%.

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Amended Credit Facility

On March 27, 2013, we entered into the first amendment (the “First Amendment”) to the Credit Facility. As a result of the First Amendment, our letters of credit sublimit was reduced from $75.0 million to $31.5 million and our available credit was reduced from $350.0 million to the sum of $250.0 million plus any amounts placed on deposit in a collateral account of our General Partner (the “Collateral Account”) and letters of credit outstanding. Amounts on deposit in the Collateral Account are pledged as collateral to the Credit Facility. On March 27, 2013, our General Partner deposited $10.0 million into the Collateral Account as required under the First Amendment. Pursuant to the First Amendment, we are allowed to pay our quarterly cash distribution of available cash for the first quarter 2013 in an amount not to exceed the amount then on deposit in the Collateral Account regardless of whether we meet certain financial covenants for the period ending March 31, 2013. Because the First Amendment did not modify our requirement to meet the financial covenants under the Credit Facility beginning March 31, 2013, and because we believed it was unlikely that we would be in compliance with our financial covenants for the quarter ending March 31, 2013, we further amended our Credit Facility as discussed below.  We incurred $0.5 million in fees in connection with the First Amendment, which have been deferred, and will be amortized over the remaining life of the Credit Facility.

On April 12, 2013, we entered into the limited waiver and second amendment (the “Second Amendment”) to the Credit Facility (as amended, the “Amended Credit Facility”), which waived our defaults relating to financial covenants in the Credit Facility for the period ending March 31, 2013 and provided more favorable financial covenants until we give notice under the Amended Credit Facility that we have achieved a consolidated total leverage ratio (the “Target Leverage Ratio”) of 4.25 to 1.00 for one quarter or 4.50 to 1.00 for two consecutive quarters, calculated excluding the benefit of cash on deposit in the Collateral Account and any equity cure amounts (the “Target Leverage Test”). The Target Leverage Test is not a required calculation under the Second Amendment, and can be calculated at our election. For any calendar quarter ending on or before December 31, 2013, we have the right (which cannot be exercised more than two times) to cure defaults under our financial covenants by having our General Partner and/or Southcross Energy LLC place additional funds into the Collateral Account (such funds being the equity cure). Our available credit continues to be subject to the availability limits described in the First Amendment.  We incurred $1.3 million in fees in connection with the Second Amendment which will be deferred and amortized over the remaining life of the Credit Facility.

As a condition to the Second Amendment, Southcross Energy LLC and our General Partner deposited into the Collateral Account a total of $34.2 million, including the $10.0 million previously deposited under the First Amendment. Additionally, Southcross Energy LLC and our General Partner agreed to deposit into the Collateral Account the proceeds they receive from cash distributions on our common and subordinated units that they own and that are attributable to the quarters ending March 31, 2013, June 30, 2013, September 30, 2013 and December 31, 2013.

The Second Amendment provides for, among other things, the following:

·an increase in our letters of credit sublimit from $31.5 million to $50.0 million;

·until we achieve the Target Leverage Ratio:

·an increase in our interest rate to be LIBOR plus 4.50% (after achieving the Target Leverage Ratio our interest rate reverts to the original pricing grid of not more than LIBOR plus 3.25%);

·a limit to our growth capital expenditures of $25.0 million for the remaining three quarters of 2013 and $25.0 million for the 18-months ending June 30, 2015 (provided that if additional cash, as required under the Second Amendment, is placed in the Collateral Account, such expenditures may be increased to $28.0 million for the remaining three quarters of 2013 and the 18-months ending June 30, 2015);

·distributions to our unitholders are effectively limited to our established minimum quarterly distribution of not more than $0.40 per unit;

·our ability to make acquisitions is limited; and

·proceeds from any new equity issuances or asset sales are to be applied to reduce any outstanding debt.

Pursuant to the Second Amendment, during the second quarter of 2013, Southcross Energy LLC and/or our General Partner are required to make an equity investment in us in an aggregate amount equal to $40.0 million in exchange for new equity securities, which distributions on such securities are required to be non-cash pay until the Target Leverage Test has been satisfied. In accordance with the Second Amendment, on April 12, 2013, we issued 1,466,325 Series A Preferred Units to Southcross Energy LLC and agreed

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to sell, by June 30, 2013, an additional 248,675 Series A Preferred Units in exchange for the investment of $40.0 million, to satisfy this requirement (See Note 11). Southcross Energy LLC and our General Partner utilized the $34.2 million on deposit in the Collateral Account to purchase the initial Series A Preferred Units on April 12, 2013.  In addition, cash distributions of $5.8 million paid by us to Southcross Energy LLC and our General Partner for the quarter ended March 31, 2013 must be deposited into the Collateral Account, and will be used to purchase the remaining 248,675 Series A Preferred Units.  The total capital infusion to us of $40.0 million from all sales of Series A Preferred Units and General Partner contributions (See Note 11), were and will be used to reduce borrowings under our Amended Credit Facility.

If we fail to meet the Target Leverage Test by June 30, 2014, all or a portion of the cash distributions we make to Southcross Energy LLC and our General Partner for the quarters ending June 30, 2013, September 30, 2013 and December 31, 2013 will be deposited into the Collateral Account and will be invested in us as additional non-cash pay equity securities until the Target Leverage Test has been satisfied. If as of June 30, 2014, the Target Leverage Test is met, any funds then on deposit in the Collateral Account (other than equity cure amounts and amounts deposited in the Collateral Account to allow the Partnership to increase the amount of its capital expenditures) will be released to Southcross Energy LLC and our General Partner.

The Second Amendment requires us to have Consolidated EBITDA (as defined in the Credit Facility) of at least $9.0 million for the quarter ending June 30, 2013, and we are not subject to a consolidated total leverage ratio for such quarter.  Additionally, we have cure rights to provide additional cash into the Collateral Account should we fall short of the$9.0 million Consolidated EBITDA covenant requirement (see below). The Second Amendment provides that until we satisfy the Target Leverage Ratio, we are allowed to calculate an adjusted consolidated total leverage ratio, which allows for the netting of total funded indebtedness with amounts on deposit in the Collateral Account, and we may not permit our adjusted consolidated total leverage ratio to exceed the ratio set forth below for the corresponding period (as provided in the Second Amendment):

	Maximum Adjusted Consolidated Total Leverage Ratio
September 30, 2013	7.25 to 1.00
December 31, 2013	6.75 to 1.00
March 31, 2014	6.25 to 1.00
June 30, 2014	5.25 to 1.00
September 30, 2014	5.00 to 1.00
December 31, 2014	4.75 to 1.00
March 31, 2015 and thereafter	4.50 to 1.00

Upon satisfying the Target Leverage Ratio, beginning with the quarter ending September 30, 2013, the Second Amendment provides that we will not permit our maximum consolidated total leverage ratio to exceed the ratio set forth below for the corresponding period (as provided in the Amended Credit Facility):

	Maximum Consolidated Total Leverage Ratio
September 30, 2013	4.75 to 1.00
December 31, 2013 and thereafter	4.50 to 1.00

The Second Amendment changed the minimum consolidated interest coverage ratio to 2.25 to 1.00 for the quarters ending September 30, 2013 and December 31, 2013 and 2.50 to 1.00 for the quarters ending March 31, 2014 and thereafter.

If, for the calendar quarters ending on or before December 31, 2013, we fail to comply with the financial covenants of the Amended Credit Facility (“Financial Covenant Default”) we have the right (which cannot be exercised more than two times) to cure such Financial Covenant Default by having Southcross Energy LLC and/or our General Partner deposit into the Collateral Account the amount required by the Second Amendment to cure such Financial Covenant Default.

After the application of the proceeds from the equity infusion on April 12, 2013, our borrowings under the Amended Credit Facility were $222.8 million and our available borrowing capacity was $27.2 million.

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6. PROPERTY, PLANT AND EQUIPMENT

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

	Estimated Useful Life	March 31, 2013			December 31, 2012
Pipelines	30	$	302,246		$	250,177
Gas processing, treating and other plants	15	221,793			221,594
Compressors	7	19,524			19,241
Rights of way and easements	15	20,729			20,729
Furniture, fixtures and equipment	5	3,139			3,087
Total property, plant and equipment		567,431			514,828
Accumulated depreciation and amortization		(53,701		)	(46,466		)
Total		513,730			468,362
Construction in progress		50,546			77,011
Land and other		5,299			5,230
Net property, plant and equipment		$	569,575		$	550,603

Depreciation is provided using the straight-line method based on the estimated useful life of each asset.  Depreciation expense for the three months ended March 31, 2013 and 2012 was $7.2 million and $3.7 million, respectively.

Costs related to projects during construction, including interest on funds borrowed to finance the construction of facilities, are capitalized as construction in progress.  For the three months ended March 31, 2013 and 2012, the Partnership capitalized interest of $0.6 million and $1.1 million, respectively.

In January 2013, we shut down our Gregory facility to perform extensive turnaround maintenance activities and to connect additional equipment to enhance NGL recoveries.  As the turnaround maintenance was nearing completion in January 2013, we experienced a fire at this facility.  In connection with the fire, we spent approximately $2.8 million to return the plant to service and filed an insurance claim related to these costs.  We believe it is probable that we will be able to recover these costs, less a $0.3 million deductible, under our current insurance policies.

7. OTHER ASSETS

Other assets consisted of the following (in thousands):

	March 31,		December 31,
	2013		2012
Deferred financing costs	$	4,721	$	4,385
Prepaid expenses	563		551
Other	195		195
Total other assets	$	5,479	$	5,131

The Partnership incurred $5.2 million in costs as a result of entering into amendments to our credit agreements during 2012.

Deferred financing costs are amortized over the life of the Credit Facility.  Amortization of deferred financing costs recorded in interest expense was $0.3 million for each of the three months ended March 31, 2013 and 2012.

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8. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

Accounts payable and accrued liabilities consisted of the following (in thousands):

	March 31,		December 31,
	2013		2012
Trade accounts payable	$	55,405	$	87,981
Accrued liabilities	6,759		8,820
Total accounts payable	$	62,164	$	96,801

Trade accounts payable as of March 31, 2013 and December 31, 2012 included $17.7 million and $40.7 million, respectively,  related to capital expenditures and such amounts have been reflected as non-cash investing activities within the condensed consolidated statement of cash flows.

9. COMMITMENTS AND CONTINGENCIES

Legal Matters

On March 5, 2013, a subsidiary of the Partnership filed suit against Formosa Hydrocarbons Company, Inc. (“Formosa”).  The lawsuit seeks recoveries of losses that we believe our subsidiary experienced as a result of the failure of Formosa to perform certain of its obligations under the gas processing contract between the parties.  Formosa has filed a response generally denying our claims. We cannot predict the outcome of such litigation or the timing of any related recoveries by the Partnership.

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. There are currently no such pending proceedings to which we are a party that our management believes 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 will ultimately have a material effect on our results of operations, cash flows or financial condition in any future reporting periods. As of March 31, 2013, we did not have any amounts accrued for our legal proceedings.

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.

Operating Leases

We maintain operating leases in the ordinary course of business activities.  These leases include those for vehicles, office buildings and other operating facilities and equipment.  The terms of the agreements vary from 2013 to 2017.  Future minimum annual rental commitments under our operating leases at March 31, 2013 were as follows (in thousands):

	Operating Leases
2013 (remaining)	$	746
2014	911
2015	657
2016	435
2017	294
Total	$	3,043

Expenses associated with operating leases were $0.5 million for the three months ended March 31, 2013 and 2012.

Purchase Commitments

At March 31, 2013, we had commitments of approximately $1.7 million to purchase equipment related to our capital projects.

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10. TRANSACTIONS WITH RELATED PARTIES

Charlesbank

Historically, Charlesbank provided certain management services to Southcross Energy LLC pursuant to a management services agreement (“Charlesbank Agreement”) that specified an annual management fee of $0.6 million. Southcross Energy LLC received services under the Charlesbank Agreement until the IPO. Concurrently with the IPO, the Charlesbank Agreement was terminated.

For the three months ended March 31, 2012, Southcross Energy LLC incurred management fees of $0.2 million for services received under the Charlesbank Agreement.

Southcross Energy GP, LLC (our General Partner)

Our General Partner does not receive a management fee or other compensation for its management of us.  However, our General Partner and its affiliates are entitled to reimbursements for all expenses incurred on our behalf, including, among other items, compensation expense for all employees required to manage and operate our business.  During the three months ended March 31, 2013, we incurred expenses of $5.9 million related to these reimbursements which were reflected in operating expenses in our consolidated statement of operations.

The reimbursement of our compensation expenses to our General Partner began on January 1, 2013 in accordance with our Partnership Agreement.

11. PARTNERS’ CAPITAL

Common Units

Our common units represent limited partner interests in us. The holders of our common units are entitled to participate in partnership distributions and are entitled to exercise the rights and privileges available to limited partners under our Partnership Agreement. We have authorized 13,963,713 common units as of March 31, 2013 and December 31, 2012.

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.

General Partner Interests

Our general partner interest consisted of 498,518 general partner units as of March 31, 2013 and December 31, 2012 and, as defined by the Partnership Agreement, are not considered to be units (common or subordinated) but are representative of the general partner’s 2.0% ownership interest in us. Subsequent to March 31, 2013 and in conjunction with the Private Placement (as defined below), our General Partner made a capital contribution in the amount of $0.7 million in exchange for an issuance of an additional 29,925 general partner units on April 12, 2013, in order to maintain its 2.0% ownership interest in us.

Series A Convertible Preferred Units

On April 12, 2013 (the “Issue Date”), we entered into a Series A Preferred Unit Purchase Agreement (the “Purchase Agreement”) with Southcross Energy LLC, pursuant to which we issued and sold 1,466,325 Series A Preferred Units to Southcross Energy LLC and agreed to sell, by June 30, 2013, an additional 248,675 Series A Preferred Units, in each case, for a cash purchase price of $22.86 per Series A Preferred Unit, in a privately negotiated transaction (the “Private Placement”).

The Series A Preferred Units are a new class of voting equity security that ranks senior to all of our other classes or series of equity securities with respect to distribution rights and rights upon liquidation.

The Series A Preferred Units have voting rights identical to the voting rights of the common units and will vote with the common units as a single class, such that each Series A Preferred Unit (including each Series A Preferred Unit issued as an in-kind distribution, discussed below) is entitled to one vote for each common unit into which such Series A Preferred Unit is convertible on each matter with respect to which each common unit is entitled to vote.

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The Private Placement resulted in proceeds to us of $33.5 million. We also received a $0.7 million capital contribution from our General Partner to maintain its 2.0% general partner interest in us. When we sell the remaining 248,675 Series A Preferred Units to Southcross Energy LLC for $5.7 million, our General Partner will make an additional capital contribution to us of $0.1 million.

The total capital infusion to the Partnership of $40.0 million, from all sales of Series A Preferred Units and General Partner capital contributions, were and will be used to reduce borrowings under our Amended Credit Facility (See Note 5).

Series A Preferred Unit Distribution Rights

Holders of Series A Preferred Units are entitled to quarterly distributions of in-kind Series A Preferred Units for the first four full quarters following the Issue Date and continuing thereafter until the board of directors of our General Partner determines to begin paying quarterly distributions in cash, and thereafter in cash. The board of directors of our General Partner may not elect to begin paying quarterly distributions on the Series A Preferred Units in cash until we have exercised the Target Leverage Option (pursuant to the Second Amendment) under our Amended Credit Facility.

In-kind distributions will be made in the form of Series A Preferred Units at a rate of $0.40 per outstanding Series A Preferred Unit per quarter (or 7% per year of the per unit purchase price) or, beginning after four full quarters, such higher per unit rate as is paid in respect of our common units. Cash distributions will equal the greater of $0.40 per unit per quarter or the quarterly distribution paid with respect to each common unit.

Series A Preferred Units Conversion Rights

Beginning on the later of January 1, 2015 and the date we exercise the Target Leverage Option (pursuant to the Second Amendment), Series A Preferred Units (including Series A Preferred Units issued as in-kind distributions) will be convertible into common units on a one-for-one basis, except that conversion will be prohibited to the extent that it would cause (on a pro forma basis) our estimated quarterly distributions over any of the succeeding four quarters to exceed our total distributable cash flow in that quarter. In addition, the Series A Preferred Units will be convertible into common units having a collective value of 110.0% of the Series A Preferred Units if a third party acquires majority ownership control of our General Partner or we sell substantially all of our assets, in either case prior to January 1, 2015.

Beginning on the later of January 1, 2015 and the date we exercise the Target Leverage Ratio (pursuant to the Second Amendment), we will have the right at any time to convert all or some of the Series A Preferred Units (including Series A Preferred Units issued as in-kind distributions) then outstanding into common units if (i) the daily volume-weighted average trading price of the common units on the national securities exchange on which the common units are listed or admitted to trading for the trailing 30-trading-day period prior to our notice of conversion is greater than 130.0% of the unit purchase price for the Series A Preferred Units, (ii) the average daily trading volume of common units on the securities exchange exceeds 40,000 common units for those 30 trading days and (iii) the conversion would not cause (on a pro forma basis) our estimated quarterly distributions over any of the succeeding four quarters to exceed our total distributable cash flow in that quarter.

12. UNIT BASED COMPENSATION

Long-Term Incentive Plan

On November 7, 2012, and in conjunction with the IPO, the Partnership established its 2012 Long-Term Incentive Plan (“Incentive Plan”), which provides incentive awards to eligible officers, employees and directors of our General Partner. Awards granted to employees under the Incentive Plan vest over a three year period in equal annual installments in either a common unit of the Partnership 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 which grant the holder the right to receive an amount equal to all or a portion of the cash distributions made on units during the period the unit remains outstanding.

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The following table summarizes information regarding awards under the Incentive Plan:

	Units		Weighted-average grant date fair value
Unvested - December 31, 2012	144,500		$	23.01
Granted units	600		$	24.41
Forefeited units	(5,000	)	$	23.01
Vested units	—		—
Unvested - March 31, 2013	140,100		$	23.02

We granted awards under the Incentive Plan, which we have classified as equity awards, with a grant date fair value of approximately $15,000 for the three months ended March 31, 2013. As of March 31, 2013, we had total unamortized compensation expense of approximately $2.9 million related to these units, which we expect to be amortized over the three year vesting period. We recognized compensation expense of approximately $0.3 million for the three months ended March 31, 2013, which is included in general and administrative expense on our consolidated statements of operations. As of March 31, 2013, we had 1,609,900 units available for issuance under the Incentive Plan.

13. REVENUES

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

	Three Months Ended March 31,
	2013		2012
Sales of natural gas	$	98,309	$	73,270
Sales of NGLs and condensate	32,419		36,817
Transportation, gathering and processing fees	13,345		10,448
Other	177		82
Total revenues	$	144,250	$	120,617

14. CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE

The Partnership’s primary markets are in South Texas, Alabama and Mississippi. The Partnership has a concentration of revenues and trade accounts receivables 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 similarly affected by changes in economic, regulatory or other factors. The Partnership analyzes the customers’ historical financial and operational information prior to extending credit.

Formosa and Sherwin Alumina Company (“Sherwin”) represent significant customers of the Partnership for each of the three months ended March 31, 2013 and 2012.  Formosa and Sherwin contributed $17.3 million and $16.9 million, or 12.0% and 11.7%, respectively, of revenues for the three months ended March 31, 2013, and $36.6 million and $11.7 million, or 30.3% and 9.7%, respectively, of revenues for the three months ended March 31, 2012.

The Partnership’s top ten customers represent 60.3% and 73.6% of consolidated revenue for the three months ended March 31, 2013 and 2012, respectively.

For the three months ended March 31, 2013 and 2012, we experienced no significant non-payment for services. At March 31, 2013, we have recorded no allowance for uncollectable accounts receivable.

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15. SUBSEQUENT EVENTS

Credit Facility

As discussed in Note 5, on April 12, 2013, we entered into the Second Amendment, which waived our defaults relating to financial covenants for the three months ending March 31, 2013 and provided us with more favorable financial covenants than were provided previously.  We believe these modified terms will allow us to operate our business and continue to meet our commitments.

Series A Convertible Preferred Units

As discussed in Note 11, on April 12, 2013, to satisfy our requirements under our Amended Credit Facility we entered into the Private Placement.

The Private Placement resulted in proceeds to us of $33.5 million. We also received a $0.7 million capital contribution from our General Partner to maintain its 2.0% general partner interest in us. When we sell the remaining 248,675 Series A Preferred Units to Southcross Energy LLC for $5.7 million, our General Partner will make an additional capital contribution to us of $0.1 million.

The total capital infusion to the Partnership of $40.0 million from all sales of Series A Preferred Units and General Partner capital contributions were and will be used to reduce borrowings under our Amended Credit Facility (See Note 5).

As of April 12, 2013, subsequent to the issuance of the Series A Preferred Units, our ownership structure is as follows:

Description	Percentage ownership
Public common units	39.2	%
Southcross Energy LLC’s Ownership:
Common units	7.1	%
Subordinated units	46.2	%
Series A Convertible Preferred units	5.5	%
General partner interest	2.0	%
Total	100	%

Partnership Distribution

On April 30, 2013, we announced a cash distribution of $0.40 per common and subordinated unit attributable to the quarter ended March 31, 2013, which will be paid on May 15, 2013 to unitholders of record on May 10, 2013.

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

Overview and How We Evaluate our Operations

Overview

Southcross Energy Partners, L.P. (the “Partnership,” “Southcross,” the “Company,” “we,” “our,” or “us”) is a Delaware limited partnership formed in April 2012 to own, operate, develop and acquire midstream energy assets. Our common units are listed on the New York Stock Exchange (“NYSE”) under the symbol “SXE.”

Southcross Energy LLC was formed in 2009 and is the predecessor of the Partnership. In connection with our initial public offering (“IPO”), Southcross Energy LLC contributed all of its operating subsidiaries (its net assets on a historical cost basis), excluding certain liabilities and all preferred units, and became the holding company of the Partnership. Southcross Energy LLC holds all of the equity interests in Southcross Energy Partners GP, LLC, a Delaware limited liability company and our general partner (“General Partner”), as well as all subordinated units and the series A convertible preferred units issued on April 12, 2013 and 7.5% of the common units of the Partnership.  Southcross Energy LLC is controlled through investment funds and entities associated with Charlesbank Capital Partners, LLC (“Charlesbank”). There was no change in the basis of accounting as a result of these transactions.

On November 7, 2012, we completed our IPO and after the completion of the IPO and full exercise of the underwriters’ option to purchase additional common units, Southcross Energy LLC’s direct and indirect equity ownership in the Partnership was 58.5%. The preceding condensed consolidated financial statements reflect the assets, liabilities, results of operations and cash flows of the Partnership beginning November 7, 2012 and Southcross Energy LLC for the periods ended prior to November 7, 2012.

See our 2012 Annual Report on Form 10-K for more information related to our organization.

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 the resulting NGLs into the various components and selling or delivering pipeline quality natural gas and NGLs to various industrial and energy markets as well as large pipeline systems. Through our network of pipelines, we provide a means of connecting our suppliers of natural gas to our customers, which include industrial, commercial and power generation customers and local distribution companies.

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 to attempt 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 ten 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 in order to provide service to our customers. We purchase, gather, process, treat, compress, transport and sell natural gas and purchase, fractionate, transport and sell NGLs primarily pursuant to the following arrangements:

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

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

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

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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 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.

Below is a table summarizing our contract mix (in thousands):

	Three Months Ended March 31,
	2013				2012
	Gross margin		Percent of total gross operating margin		Gross margin		Percent of total gross operating margin
Fixed-fee	$	13,396	71.0	%	$	11,017	51.4	%
Fixed-spread	3,499		18.6	%	5,027		23.5	%
Sub-total	16,895		89.6	%	16,044		74.9	%
Commodity sensitive	1,967		10.4	%	5,371		25.1	%
Total gross operating margin	$	18,862	100.0	%	$	21,415	100.0	%

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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 (i) volume, (ii) gross operating margin, (iii) operations and maintenance expenses, (iv) Adjusted EBITDA and (v) 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 contract 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.

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, 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, as it does not include deductions for items such as depreciation, amortization, interest and income taxes, which may be necessary to maintain the business.

We define Adjusted EBITDA as net income, plus interest expense, income tax expense, depreciation and amortization expense, certain non-cash charges such as non-cash equity compensation, unrealized losses on commodity derivative contracts and selected charges and transaction costs that are unusual or non-recurring, less interest income, income tax benefit, unrealized gains on commodity derivative contracts 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 our 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 the Partnership’s 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 alternative investment opportunities.

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

Distributable cash flow is used to assess:

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

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

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Non-GAAP Financial Measures

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 and results of 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) income (in thousands):

	Three Months Ended March 31,
	2013			2012
Reconciliation of gross operating margin to net (loss) income
Gross operating margin	$	18,862		$	21,415
(Deduct):
Income tax expense	(18		)	(85		)
Interest expense	(2,047		)	(1,799		)
General and administrative expense	(6,041		)	(2,433		)
Depreciation and amortization expense	(7,249		)	(3,665		)
Operations and maintenance expense	(9,889		)	(7,197		)
Net (loss) income	$	(6,382	)	$	6,236

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

	Three Months Ended March 31,
	2013			2012
Reconciliation of net cash flows (used in) provided by operating activities to net (loss) income, Adjusted EBITDA and distributable cash flow
Net cash flows (used in) provided by operating activities	$	(1,711	)	$	4,638
Add (deduct):
Depreciation and amortization expense	(7,249		)	(3,665		)
Unit-based compensation	(408		)	—
Deferred financing costs amortization	(267		)	(283		)
Unrealized losses	—			(222		)
Changes in operating assets and liabilities:
Trade accounts receivable	(8,648		)	(5,564		)
Prepaid expenses and other	(1,199		)	(668		)
Other non-current assets	13			135
Accounts payable and accrued expenses	11,725			9,768
Accrued expenses and other liabilities	1,362			2,097
Net (loss) income	$	(6,382	)	$	6,236
Add:
Depreciation and amortization expense	7,249			3,665
Interest expense	2,047			1,799
Unrealized losses	—			222
Unit-based compensation	408			—
Income tax expense	18			85
Expenses associated with significant items	1,201			—
Adjusted EBITDA	$	4,541		$	12,007
(Deduct):
Cash interest, net of capitalized costs	(1,780		)	(1,290		)
Income tax expense	(18		)	(85		)
Maintenance capital expenditures	(708		)	(348		)
Distributable cash flow	$	2,035		$	10,284

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Current Year Highlights

The following events took place during the three months ended March 31, 2013 and have impacted or are likely to impact our financial condition and results of operations.

Financing Activities

Credit Facility

On March 27, 2013, we entered into the first amendment to our $350.0 million senior secured credit facility (“Credit Facility”). On April 12, 2013, we entered into the limited waiver and second amendment (the “Second Amendment”) to the Credit Facility (as amended, the “Amended Credit Facility”), which waived our defaults under the Credit Facility relating to financial covenants for the period ending March 31, 2013 and provided us with more favorable financial covenants than were provided previously. We believe these modified terms will allow us to operate our business and continue to meet our commitments. See further discussion included in Item 1. Financial Statements, Note 5 “Long-Term Debt” of this report.

Series A Convertible Preferred Units

On April 12, 2013, to satisfy our requirements under our Amended Credit Facility, we entered into a Series A Convertible Preferred Unit Purchase Agreement with Southcross Energy LLC, pursuant to which we issued and sold 1,466,325 Series A Convertible Preferred Units (“Series A Preferred Units”) and agreed to sell, by June 30, 2013, an additional 248,675 Series A Preferred Units to Southcross Energy LLC, in each case, for a cash purchase price of $22.86 per Series A Preferred Unit, in a privately negotiated transaction (the “Private Placement”). See further discussion included in Item 1. Financial Statements, Note 11 “Partners’ Capital” of this report.

Key Factors Affecting Operating Results and Financial Condition

·Bonnie View NGL fractionation facility. In February 2013, we completed the expansion of our NGL capacity at our Bonnie View fractionation facility, increasing its capacity to 22,500 Bbls/d.  The plant initiated operations in November 2012 with capacity of 11,500 Bbls/d.  The plant fractionates y-grade NGLs from our Woodsboro processing plant and produces NGL component products.

·Bonnie View start-up lost revenue and expenses. Following the start-up of our Bonnie View fractionation facility during the fourth quarter of 2012, we experienced periods of reduced recoveries and off-specification production of NGLs. This continued into the three month period ended March 31, 2013, which caused us to sell non-purity products at reduced prices or leave NGLs in the natural gas stream and sell them at natural gas equivalent prices.

·Bee Line gas pipeline commences operations. In February 2013, we completed construction of our 20-inch Bee Line pipeline to move rich gas to our Woodsboro processing plant.  The Bee Line is a 57-mile pipeline with capacity of 320 MMcf/d.

·Gregory processing and NGL fractionation facility.  We shut down the Gregory facility in January 2013 to perform extensive turnaround maintenance activities and connect additional equipment to enhance NGL recoveries.  As the turnaround maintenance was nearing completion in January 2013, we experienced a fire at this facility.  Damage was limited to a small portion of the facility. We resumed operations in April 2013, and we expect to resume full operations in May 2013.  In connection with the fire, we spent approximately $2.8 million to return the plant to service and filed an insurance claim related to these costs.  We believe it is probable that we will be able to recover these costs, less a $0.3 million deductible, under our current insurance policies.

·New long-term sales contract.  In March 2013, we entered into new firm sales contracts for propane, butane and natural gasoline produced at both our Bonnie View and Gregory NGL fractionation facilities. Deliveries under these contracts begin in May 2013 and provide us with additional markets at fixed differentials to NGL index prices, which are expected to enhance our earnings.

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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,
	2013			2012
Revenues	$	144,250		$	120,617
Expenses:
Cost of natural gas and liquids sold	125,388			99,202
Operations and maintenance	9,889			7,197
Depreciation and amortization	7,249			3,665
General and administrative	6,041			2,433
Total expenses	148,567			112,497
(Loss) income from operations	(4,317		)	8,120
Interest expense	(2,047		)	(1,799		)
(Loss) income before income tax expense	(6,364		)	6,321
Income tax expense	(18		)	(85		)
Net (loss) income	$	(6,382	)	$	6,236
Other financial data:
Adjusted EBITDA	$	4,541		$	12,007
Gross operating margin	$	18,862		$	21,415
Maintenance capital expenditures	$	708		$	348
Expansion capital expenditures	$	48,495		$	38,564
Operating data:
Average throughput of gas (MMBtu/d)	602,820			563,915
Average volume of processed gas (MMBtu/d)	239,757			212,699
Average volume of NGLs sold (Bbls/d)	10,152			9,172
Realized prices on natural gas volumes sold/Btu ($/MMBtu)	$	3.44		$	2.69
Realized prices on NGL volumes sold/gal ($/gal)	$	0.84		$	1.05

The following table summarizes our average natural gas throughput volumes, amount of NGLs delivered and volume of processed gas:

	Three Months Ended March 31,
	2013	2012
Average throughput volumes of natural gas (MMBtu/d)
South Texas	399,535	357,327
Mississippi/Alabama	203,285	206,588
Total average throughput volumes of natural gas	602,820	563,915
Average volume of processed gas (MMBtu/d)	239,757	212,699
Average volume of NGLs sold (Bbls/d)	10,152	9,172

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Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012

Volume and overview.  Our average volume of natural gas per day increased 7% to 602,820 MMBtu/d during the three months ended March 31, 2013, compared to 563,915 MMBtu/d during the three months ended March 31, 2012. Processed gas volumes increased 13% to 239,757 MMBtu/d during the three months ended March 31, 2013, compared to 212,699 MMBtu/d during the three months ended March 31, 2012, reflecting the increase in rich gas volumes processed at our facilities.

The average volume of NGLs produced for the three months ended March 31, 2013 was 10,152 Bbls/d, an increase of 11%, compared to 9,172 Bbls/d for the three months ended March 31, 2012. This increase was due to the impact of increased volumes of rich gas processed at our facilities.

Gross operating margin, for the three months ended March 31, 2013, declined to $18.9 million, compared to $21.4 million for the three months ended March 31, 2012.  This decrease of 12% was due primarily to decreased margins realized on NGLs due to lower prices realized for our off-specification products.  Adjusted EBITDA decreased by 63% to $4.5 million for the three months ended March 31, 2013, compared to $12.0 million for the three months ended March 31, 2012, due primarily to the negative effects of the issues mentioned above, coupled with higher operations and maintenance expenses and higher general and administrative expenses due to increased spending to build our operating and administrative infrastructure.  We had a net loss of $6.4 million for the three months ended March 31, 2013 compared to net income of $6.2 million for the three months ended March 31, 2012. Net income declined for the same reasons stated above as well as higher depreciation and amortization expense and interest expense.

Revenues.  Our total revenue for the three months ended March 31, 2013 was $144.3 million, compared to $120.6 million for the three months ended March 31, 2012.  This increase of $23.7 million, or 20%, was due primarily to the impact of increased realized prices on natural gas sales contracts, in addition to an increase in natural gas sales volumes.  Revenue from sales of NGLs and condensate decreased $4.4 million or 12% to $32.4 million for the three months ended March 31, 2013 compared to $36.8 million for the three months ended March 31, 2012, reflecting the lower NGL prices realized which partially offset the benefit of new volumes delivered to our processing plants.  Realized average natural gas and NGL prices were as follows:

	Three Months Ended March 31,
	2013	2012
Natural Gas	$3.44/MMBtu	$2.69/MMBtu
NGLs	$0.84/gal	$1.05/gal

Cost of natural gas and NGLs sold.  Our cost of natural gas and NGLs sold for the three months ended March 31, 2013 was $125.4 million, compared to $99.2 million for the three months ended March 31, 2012. This increase of $26.2 million, or 26%, was due primarily to higher volumes of natural gas purchased at higher prices than in the same period in 2012 as well as increased NGL volumes offset by lower NGL prices.

Operations and maintenance expense.  Operations and maintenance expense for the three months ended March 31, 2013 was $9.9 million, compared to $7.2 million for the three months ended March 31, 2012. This increase of $2.7 million, or 37%, was due primarily to $1.5 million in costs related to operating the Woodsboro and Bonnie View plants for the three months ended March 31, 2013, as Bonnie View commenced operations in the fourth quarter 2012.  In addition, we incurred higher costs for the three months ended March 31, 2013 compared to the three months ended March 31, 2012 at our Gregory processing plant related to turnaround maintenance and costs related to the fire experienced at the plant.  Lastly, we had increased ad valorem and other taxes due to investments and expansion of our assets and higher labor and benefit costs due to increased staffing to support our expansion.

General and administrative (‘‘G&A’’) expenses.  G&A expenses for the three months ended March 31, 2013 were $6.0 million, compared to $2.4 million for the three months ended March 31, 2012. This increase of $3.6 million, or 148%, was due primarily to increased expenses from third parties related to the establishment of our public reporting accounting processes, employee related expenses and insurance coverage to support our growing operations and expenses to build our corporate and support infrastructure.

Depreciation and amortization expense.  Depreciation and amortization expense for the three months ended March 31, 2013 was $7.2 million, compared to $3.7 million for the three months ended March 31, 2012.  The increase of $3.6 million, or 98%, was due primarily to the completion of growth capital expenditures made during the second half of 2012 and the first three months of 2013.

Interest expense.  For the three months ended March 31, 2013, net interest expense was $2.0 million, compared to $1.8 million for the three months ended March 31, 2012. This increase was due to higher average borrowings compared to the same period in 2012.

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Liquidity and Capital Resources

Sources of Liquidity

Cash generated from operations, investments by Charlesbank and other investors, equity raised through the IPO and other equity issuances and borrowings under our predecessor’s credit facility and the Credit Facility have been our primary sources of liquidity. Our primary cash requirements consist of operating and G&A expenses, maintenance capital expenditures to sustain existing operations or generate additional revenues, interest payments on outstanding debt, acquisitions of new assets or businesses and distributions to unitholders.

The Partnership expects to fund short term cash requirements, such as operating and G&A expenses and maintenance capital expenditures to sustain existing operations, 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 Amended Credit Facility and issuances of additional equity and debt securities, as appropriate and subject to market conditions. The Partnership’s ability to fund expansion projects through the use of its Amended Credit Facility is limited to $25.0 million during the remaining three quarters of 2013 and $25.0 million in the 18-month period ending June 30, 2015, which can be increased to $28.0 million in each period if additional funds are placed into the Collateral Account (as defined in the Second Amendment). The Partnership does not expect these limitations to significantly affect current operations or future projects. See Item 1. Financial Statements, Note 5 “Long-Term Debt” of this report for a description of the amendments to the Credit Facility.

Capital resources.  The Partnership’s business is capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of and will continue to be:

·maintenance capital expenditures, which are capital expenditures made to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows; and

·growth capital expenditures, which are capital expenditures made 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, whether through construction or acquisition.

During the three months ended March 31, 2013, capital expenditures totaled $49.2 million, consisting of $0.7 million of maintenance capital and $48.5 million of growth capital. The growth capital expenditures during the three months ended March 31, 2013, primarily related to (i) our Bonnie View NGL fractionation facility completed in February 2013, and (ii) our new Bee Line pipeline completed in February 2013.

During the remaining three quarters of 2013, we expect to spend $20.0 million to $25.0 million on growth capital projects.

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.

Commodity prices and financial market conditions continue to support opportunities for volume growth from shale resource plays. The Partnership’s ability to benefit from growth projects to accommodate strong drilling activity 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 underperformance 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. For example, we encountered operational difficulties in connection with the start-up of our Bonnie View fractionator, the curtailment by our third party processor and a fire at our Gregory facility that had a negative impact on our results in the fourth quarter of 2012 and first quarter of 2013. 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 the Partnership’s ability to comply with its debt covenants would likewise be affected adversely if we experienced declining volumes over a sustained period in combination with unfavorable commodity prices.

Our historical financing strategy for funding long-term capital expenditures has been to target a roughly equal mix of debt and equity financing and a consolidated leverage ratio which complied with our credit agreement covenants. During the fourth quarter of 2012 and into the first quarter of 2013, we encountered operational difficulties having an adverse impact our operating results. As a result of this negative impact, prior to March 31, 2013, we believed it was unlikely that we would be in compliance with our financial covenants calculated for the quarter ending March 31, 2013, such that, in conjunction with additional equity invested into the

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Partnership, we negotiated with our lenders and secured more favorable financial covenants and amended our Credit Facility. As a result of the amendments to the Credit Facility, and after giving effect to the equity infusion and its use to repay debt on April 12, 2013, we had $27.2 million of borrowing capacity under our Amended Credit Facility. As of April 30, 2013, we have $17.2 million of borrowing capacity under our Amended Credit Facility. Consequently, we believe we have and will continue to have sufficient liquidity to operate our business as the Amended Credit Facility provides us with more favorable financial covenants than were provided previously and we believe these more favorable terms will allow us to operate our business and continue to meet our commitments.

We believe that cash from operations, cash on hand and available capacity under our Amended Credit Facility will provide liquidity to meet future short term capital requirements and to fund committed capital expenditures for the remainder of 2013. The sufficiency of these liquidity sources to fund necessary and committed capital needs will be dependent upon our ability to meet our newly established covenant requirements of our Amended Credit Facility. Please read Item 1. Financial Statements, Note 5 “Long-Term Debt” of this report for a description of the amendments we have entered into with respect to our Credit Facility.

Organic expansion projects and acquisitions are key elements of our business strategy. We intend to finance the Partnership’s 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,
	2013			2012
Net cash (used in) provided by operating activities	$	(1,711	)	$	4,638
Net cash used in investing activities	$	(52,028	)	$	(38,912	)
Net cash provided by financing activities	$	48,499		$	46,847

Operating cash flows — Net cash used in operating activities was $1.7 million for the three months ended March 31, 2013, compared to net cash provided by operating activities of $4.6 million for the three months ended March 31, 2012.  The decrease in cash from operating activities was the result of lower net income, net of non-cash charges of $8.9 million.  In addition, the overall decrease in operating cash flows of $6.3 million included a decrease in the change in operating assets and liabilities of $2.5 million due primarily to expenditures related to increases to operating expenses period over period due to our increased operations to build our operating and administrative infrastructure and the annual payment of property taxes of $4.0 million during the quarter ended March 31, 2013.

Investing cash flows — Net cash used in investing activities for the three months ended March 31, 2013 was $52.0 million, compared to $38.9 million for the three months ended March 31, 2012.  The increase of $13.1 million relates primarily to the increase in capital spending period over period primarily related to the completion of the Bee Line and Bonnie View plant in February 2013.  During the three months ended March 31, 2013, we spent $48.0 million in growth capital and $0.7 million in maintenance capital.  In addition to capital spending, we spent $2.8 million at our Gregory facility related to the fire that occurred during January 2013 to return the plant to service.  We have filed an insurance claim related to these costs spent during the three months ended March 31, 2013.  We believe it is probable that we will be able to recover these costs, less a $0.3 million deductible, under our current insurance policies.

Financing cash flows — The increase in cash flow provided by financing activities of $1.7 million for the three months ended March 31, 2013 compared to the three months ended March 31, 2012 was due to increased net borrowings of $25.9 million period over period offset by distributions paid to partners of $6.0 million during February 2013.  For the three months ended March 31, 2012, our predecessor received net proceeds of $17.7 million from the issuance of Series B redeemable preferred units offset by the repurchase and retirement of Southcross Energy LLC common units and financing costs paid.  We did not receive similar proceeds during the three months ended March 31, 2013.

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Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Recent Accounting Pronouncements

For information on new accounting pronouncements, see Note 2, “Basis of Presentation and Summary of Significant Accounting Policies” included in Item 1. of this report.

Critical Accounting Policies and Estimates

Our critical accounting policies are described in our 2012 Annual Report on Form 10-K.  The preparation of financial statements in conformity with GAAP requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no significant changes to our critical accounting policies since our 2012 Annual Report on Form 10-K.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate. Both profitability and cash flow are affected by volatility in the prices of these commodities. Natural gas and NGL prices are impacted by changes in the supply and demand for natural gas and NGLs, as well as market uncertainty. Adverse effects on cash flow from increases or reductions in natural gas and NGL product prices could adversely affect our ability to make distributions to unitholders. We manage this commodity price exposure through an integrated strategy that includes management of the commercial terms of our contract portfolio by entering into fixed-fee-based or fixed-spread arrangements whenever possible and the use of swing swaps. Swing swaps are generally short term in nature (one month) and are usually entered into to protect against changes in the volume of daily versus first-of-month index priced gas supplies or markets. We have not entered into any long-term derivative contracts to manage exposure to commodity price risk. Natural gas and NGL prices, however, also can affect profitability indirectly by influencing the level of drilling activity in our areas of operation. We are a net seller of NGLs and, as such, financial results also are exposed to fluctuations in NGL price levels.

A hypothetical increase or decrease in commodity prices by 1.0% would have changed our gross operating margin by $0.1 million for the three months ended March 31, 2013.

Interest Rate Risk

We have exposure to changes in interest rates on indebtedness. In March 2012, we entered into an interest rate swap contract for $150.0 million notional amount of debt. The contract effectively caps our LIBOR based interest rate exposure on $150.0 million of debt at 0.54% through June 30, 2014.

The credit markets have recently experienced historical lows in interest rates. As the overall economy strengthens, it is possible that monetary policy will tighten, resulting in higher interest rates. Interest rates on floating rate credit facilities and future debt offerings could be higher than current levels, causing the Partnership’s financing costs to increase accordingly.

A hypothetical increase or decrease in interest rates by 1.0% would have changed our interest expense by $0.8 million for the three months ended March 31, 2013.

Risk Relating to NGLs

Recovery Commitments

We have operational exposure under several gas supply and transportation agreements that contain fixed percentage NGL recovery obligations.  To the extent that we do not produce, sell or re-deliver under transportation agreements at least as many gallons of NGLs as required under those respective supply and transportation agreements, we are exposed to the equivalent cost of the respective NGL products at NGL market prices net of contractual discounts, offset by the value of the unrecovered NGL products sold at methane natural gas prices.  Similarly, to the extent that we produce, sell or re-deliver more gallons of NGLs under transportation agreements than required under these agreements, we are able to sell the excess NGL products for our own account.

A hypothetical increase or decrease in NGL volumes recovered of 1.0% would have changed our gross operating margin by $0.2 million for the three months ended March 31, 2013.

Pricing Differential

We are exposed to the risk that we will be unable to sell NGLs at the expected differential to index prices necessary to preserve fixed-spread margins. To the extent that we do not produce marketable purity NGL products, due to operational disruptions or NGL market disruptions, we are exposed to the incremental difference between the price differential to index realized and our current differential to index price.

A hypothetical increase or decrease of $0.01 in our realized NGL gross operating margin spread per gallon would have changed our gross operating margin by $0.4 million for the three months ended March 31, 2013.

Impact of Seasonality

The results of operations were not affected materially by seasonality.

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Item 4.  Controls and Procedures.

Disclosure controls.  The Chief Executive Officer and Chief Financial Officer of our General Partner, who are responsible for the management of the Partnership, 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 Quarterly Report on Form 10-Q (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 have been no changes in internal controls over financial reporting (as defined in Rule 13(a)—15(f) or Rule 15d—15(f) of the Exchange Act) during the first fiscal quarter of 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1.  Legal Proceedings.

A description of our material legal proceedings is included in Part 1. Financial Statements, Note 9, “Commitments and Contingencies” of this report, and is incorporated herein by reference.

Item 1A. Risk Factors.

The Risk Factors contained in our 2012 Annual Report on Form 10-K under Part 1A. “Risk Factors” are incorporated herein by reference. There have been no material changes in our risk factors since that report.

These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or results of operations.

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

The disclosures related to the Private Placement of the Series A Convertible Preferred Units is included in Part II Item 9B. “Other Information” in our 2012 Annual Report on Form 10-K and are incorporated herein by reference.

Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Not applicable.

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Item 6. Exhibits.

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	First Amended and Restated Agreement of Limited Partnership of Southcross Energy Partners, L.P., dated as of November 7, 2012 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K dated November 7, 2012).
3.3	Second Amended and Restated Agreement of Limited Partnership of Southcross Energy Partners, L.P., dated as of April 12, 2013 (incorporated by reference to Exhibit 3.3 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2012).
3.4	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)).
3.5	Amended and Restated Limited Liability Company Agreement of Southcross Energy Partners GP, LLC, dated as of November 7, 2012 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K dated November 7, 2012).
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 the Annual Report on Form 10-K for the fiscal year ended December 31, 2012).
10.1	First Amendment to Second Amended and Restated Credit Agreement, dated as of March 27, 2013, by and among Southcross Energy Partners, L.P., Wells Fargo Bank, N.A., as Administrative Agent, and each of the Lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated March 28, 2013).
10.2	Limited Waiver and Second Amendment to Second Amended and Restated Credit Agreement, dated as of April 12, 2013, by and among Southcross Energy Partners, L.P., Wells Fargo Bank, N.A., as Administrative Agent, and each of the Lenders party thereto (incorporated by reference to Exhibit 10.5 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2012).
10.3	Southcross Energy Partners GP, LLC Non-Employee Director Compensation Arrangement (incorporated by reference to Exhibit 10.12 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2012).
10.4	Southcross Energy Partners, L.P. Non-Employee Director Deferred Compensation Plan (incorporated by reference to Exhibit 10.13 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2012).
10.5	Series A Preferred Unit Purchase Agreement, dated as of April 12, 2013, by and between Southcross Energy Partners, L.P. and Southcross Energy LLC (incorporated by reference to Exhibit 10.14 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2012).
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

* Filed or furnished herewith.

† Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections. The financial information contained in the XBRL (eXtensible Business Reporting Language)-related documents is unaudited and unreviewed.

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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 8, 2013	By:	/s/ J. Michael Anderson
		J. Michael Anderson
		Senior Vice President and Chief Financial Officer
		Principal Financial Officer
Date: May 8, 2013	By:	/s/ Donna Henderson
		Donna Henderson
		Vice President and Chief Accounting Officer
		Principal Accounting Officer

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