Edgar Filing: Southcross Energy Partners, L.P.

SXE - 2013.9.30 - 10Q - Q3

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended September 30, 2013



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

For the transition period from to

Commission File Number: 001-35719

Southcross Energy Partners, L.P.

(Exact name of registrant as specified in its charter)



DELAWARE		45-5045230
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)



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 ý No o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer o		Accelerated filer 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 ý

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 November 13, 2013, the registrant has 12,267,019 common units outstanding, 12,213,713 subordinated units outstanding and 1,739,473 Series A Convertible Preferred Units outstanding. Our common units trade on the NYSE under the symbol “SXE.”

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Commonly Used Terms

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

/d: Per day

/gal: Per gallon

Bbls: Barrels

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

MMBtu: One million British thermal units

Mcf: One thousand cubic feet

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, normal butane and natural gasoline

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FORM 10-Q

TABLE OF CONTENTS

Southcross Energy Partners, L.P.



FORWARD-LOOKING INFORMATION		4

PART I — FINANCIAL INFORMATION		5

ITEM 1.	Financial Statements (Unaudited)	5

	Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012	5

	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2013 and 2012	6

	Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2013 and 2012	7

	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2013 and 2012	8

	Condensed Consolidated Statements of Changes in Partners’ Capital and Members’ Equity for the Nine Months Ended September 30, 2013 and 2012	9

	Notes to Condensed Consolidated Financial Statements (unaudited)	10

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	35

ITEM 4.	Controls and Procedures	36

PART II — OTHER INFORMATION		36

ITEM 1.	Legal Proceedings	36

ITEM 1A.	Risk Factors	36

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	36

ITEM 3.	Defaults Upon Senior Securities	36

ITEM 4.	Mine Safety Disclosures	36

ITEM 5.	Other Information	36

ITEM 6.	Exhibits	39

SIGNATURES		38

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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 such 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 and fractionation 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)



	September 30, 2013			December 31, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	786		$	7,490
Trade accounts receivable	52,185			50,994
Prepaid expenses	2,263			1,762
Other current assets	3,551			1,001
Total current assets	58,785			61,247

Property, plant and equipment, net	579,051			550,603
Intangible assets, net	1,582			1,624
Other assets	6,383			5,131
Total assets	$	645,801		$	618,605

LIABILITIES, PREFERRED UNITS AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	55,062		$	96,801
Other current liabilities	5,901			3,586
Total current liabilities	60,963			100,387

Long-term debt	258,500			191,000
Other non-current liabilities	1,618			751
Total liabilities	321,081			292,138

Commitments and contingencies (Note 9)

Series A convertible preferred units (1,739,473 units issued and outstanding as of September 30, 2013)	40,089			—

Partners’ capital:
Common units (13,963,713 units authorized; 12,222,692 and 12,213,713 units issued and outstanding as of September 30, 2013 and December 31, 2012, respectively)	173,871			194,365
Subordinated units (12,213,713 units authorized, issued and outstanding as of September 30, 2013 and December 31, 2012)	104,457			125,951
General Partner interest	6,590			6,628
Accumulated other comprehensive loss	(287		)	(477		)
Total partners’ capital	284,631			326,467
Total liabilities, preferred units and partners’ capital	$	645,801		$	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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Revenues	$	160,629		$	118,150		$	459,583		$	344,469
Expenses:
Cost of natural gas and liquids sold	135,416			103,073			394,212			289,277
Operations and maintenance	10,896			8,890			31,069			24,469
Depreciation and amortization	9,447			5,522			24,958			12,860
General and administrative	5,227			3,351			16,850			8,987
Total expenses	160,986			120,836			467,089			335,593

(Loss) income from operations	(357		)	(2,686		)	(7,506		)	8,876
Interest expense, net	(3,587		)	(1,362		)	(8,735		)	(4,493		)
(Loss) income before income tax expense	(3,944		)	(4,048		)	(16,241		)	4,383
Income tax benefit (expense)	(125		)	7			(404		)	(249		)
Net (loss) income	(4,069		)	(4,041		)	(16,645		)	4,134
Series A preferred unit in-kind distribution	(696		)				(1,255		)
Series A preferred unit valuation adjustment to maximum redemption value	4,667						—
Net loss attributable to partners	(98		)				(17,900		)

General partner’s interest in net loss	(81		)				(334		)
Limited partners’ interest in net loss	$	(17	)				$	(17,566	)

Less deemed dividends on:
Redeemable preferred units				(820		)				(2,339		)
Series B redeemable preferred units				(2,038		)				(3,822		)
Series C redeemable preferred units				(1,364		)				(1,423		)
Preferred units				(3,978		)				(11,564		)
Net loss attributable to Southcross Energy LLC common unitholders				$	(12,241	)				$	(15,014	)

Basic and diluted net (loss) income per unit:
Basic net (loss) income per common unit	$	0.19					$	(0.72	)
Diluted net loss per common unit	$	(0.14	)				$	(0.72	)

Basic and diluted net loss per subordinated unit	$	(0.19	)				$	(0.72	)

Basic and diluted net loss per Southcross Energy LLC common unit				$	(10.09	)				$	(12.36	)

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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Net (loss) income	$	(4,069	)	$	(4,041	)	$	(16,645	)	$	4,134
Other comprehensive income (loss):
Hedging losses reclassified to earnings and recognized in interest expense	108			84			302			169
Adjustment in fair value of derivatives	(82		)	(379		)	(112		)	(728		)
Total other comprehensive income (loss)	26			(295		)	190			(559		)
Comprehensive (loss) income	$	(4,043	)	$	(4,336	)	$	(16,455	)	$	3,575

See accompanying notes.

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SOUTHCROSS ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)



	Nine Months Ended September 30,
	2013			2012
Cash flows from operating activities:
Net (loss) income	$	(16,645	)	$	4,134
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and amortization	24,958			12,860
Unit-based compensation	1,645			293
Amortization of deferred financing costs	947			948
Unrealized loss	—			222
Other, net	(63		)	—
Changes in operating assets and liabilities:
Trade accounts receivable	(1,191		)	(2,292		)
Prepaid expenses and other current assets	(335		)	(198		)
Other non-current assets	(60		)	(1,598		)
Accounts payable and accrued liabilities	(7,502		)	(166		)
Interest payable	—			75
Other liabilities	1,708			784
Net cash provided by operating activities	$	3,462		$	15,062
Cash flows from investing activities:
Capital expenditures	$	(86,149	)	$	(112,450	)
Expenditures related to repair of Gregory plant fire damage, net of insurance proceeds and deductible	(2,716		)	—
Other	45			—
Net cash used in investing activities	$	(88,820	)	$	(112,450	)
Cash flows from financing activities:
Borrowings under our credit agreements	$	107,500		$	88,500
Repayments under our credit agreements	(40,000		)	(43,618		)
Payments on capital lease obligations	(398		)	—
Financing costs	(2,139		)	(2,513		)
Proceeds from issuance of Series A convertible preferred units, net of issuance costs	38,832			—
Contributions from general partner	800			—
Repurchase and retirement of Southcross Energy LLC common units	—			(15,300		)
Proceeds from issuance of Southcross Energy LLC Series B redeemable preferred units	—			42,800
Proceeds from issuance of Southcross Energy LLC Series C redeemable preferred units	—			30,000
Distribution to partners	(25,941		)	—
Net cash provided by financing activities	$	78,654		$	99,869
Net (decrease) increase in cash and cash equivalents	(6,704		)	2,481
Cash and cash equivalents — Beginning of period	7,490			1,412
Cash and cash equivalents — End of period	$	786		$	3,893
Supplemental Disclosures:
Cash paid for interest, net of amounts capitalized	$	8,880		$	7,820
Cash paid for taxes, net of refunds received	$	95		$	320

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
										Accumulated Other
	Limited Partners									Comprehensive
	Common			Subordinated			General Partner			Loss			Total
BALANCE - December 31, 2012	$	194,365		$	125,951		$	6,628		$	(477	)	$	326,467
Net loss	(8,172		)	(8,164		)	(309		)	—			(16,645		)
Series A preferred unit in-kind distribution	(615		)	(615		)	(25		)	—			(1,255		)
Issuance of general partner units	—			—			800			—			800
General partner unit in-kind distribution	(13		)	(12		)	25			—			—
Unit-based compensation on long-term incentive plan	1,206			—			—			—			1,206
Cash distributions paid	(12,709		)	(12,703		)	(529		)	—			(25,941		)
Net effect of cash flow hedges	—			—			—			190			190
Accrued distribution on long-term incentive plan	(191		)	—			—			—			(191		)
BALANCE - September 30, 2013	$	173,871		$	104,457		$	6,590		$	(287	)	$	284,631



	Members’ Equity						Accumulated Other
	Common			Accumulated			Comprehensive
	Equity			Deficit			Loss			Total
BALANCE - December 31, 2011	$	1,473		$	(11,638	)	$	—		$	(10,165	)
Net income	—			4,134			—			4,134
Other comprehensive loss	—			—			(559		)	(559		)
Deemed dividend on redeemable preferred units	—			(2,339		)	—			(2,339		)
Deemed dividend on Series B redeemable preferred units	—			(3,822		)	—			(3,822		)
Deemed dividend on Series C redeemable preferred units	—			(1,423		)	—			(1,423		)
Deemed dividend on preferred units	—			(11,564		)	—			(11,564		)
Repurchase and retirement of common units	(131		)	(15,170		)	—			(15,301		)
BALANCE - September 30, 2012	$	1,342		$	(41,822	)	$	(559	)	$	(41,039	)

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,” “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 our predecessor. In connection with our initial public offering of common units (“IPO”) on November 7, 2012, 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 our holding company. 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”), all of our subordinated units, as well as a portion of our common units outstanding and our Series A Convertible Preferred Units (“Series A Preferred Units”) originally issued during the second quarter of 2013 (See Note 11). 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.

The condensed consolidated financial statements reflect our financial position, results of operations and cash flows beginning November 7, 2012 and those of Southcross Energy LLC for the reported periods ended before November 7, 2012.

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

Description of Business

We are 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 NGL fractionation and transportation services. We also source, purchase, transport and sell natural gas and NGLs. Our network of pipelines connects supplies 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 (this “report”) 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 September 30, 2013, and for the three and nine months ended September 30, 2013 and 2012, are unaudited. 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 and estimates necessary for the fair presentation of the results of operations for the periods presented. Actual results could differ from those estimates. Information for interim periods may not be indicative of our operating results for the entire year.

The disclosures included in this report provide an update to our 2012 Annual Report on Form 10-K.

We evaluate events that occur after the balance sheet date, but before the financial statements are issued, for potential recognition or disclosure. Based on the evaluation, we determined that there were no material subsequent events for recognition or disclosure other than those disclosed herein.

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Significant Accounting Policies

During the third quarter of 2013, 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, and currently there are no new accounting pronouncements that would have a material impact.

3. NET (LOSS) INCOME PER LIMITED PARTNER UNIT AND DISTRIBUTIONS

Net (Loss) Income Per Limited Partner Unit

The following is a reconciliation of the net loss attributable to our limited partners and our limited partner units and the basic and diluted earnings per unit calculations for the three and nine months ended September 30, 2013 (in thousands, except unit and per unit data):



	Three Months Ended September 30, 2013			Nine Months Ended September 30, 2013
Net loss	$	(4,069	)	$	(16,645	)
Series A Preferred Unit distribution	(696		)	(1,255		)
Series A Preferred Unit valuation adjustment to maximum redemption value (1)	4,667			—
Net loss attributable to partners	$	(98	)	$	(17,900	)

General partner’s interest	$	(81	)	$	(334	)
Limited partners’ interest:
Common (1)	$	2,323		$	(8,784	)
Subordinated	$	(2,340	)	$	(8,782	)



Common Units	Three Months Ended September 30, 2013			Nine Months Ended September 30, 2013
Interest in net (loss) income	$	2,323		$	(8,784	)
Effect of dilutive units - numerator:
Series A Preferred Unit distribution	341			—
Series A Preferred Unit valuation adjustment to maximum redemption value (1)	(4,667		)	—
Dilutive interest in net loss	$	(2,003	)	$	(8,784	)

Weighted-average units - basic	12,222,692			12,219,699
Effect of dilutive units - denominator (2):
Series A Preferred Units	1,739,473			—
Awards granted under long-term incentive plan	27,972			—
Weighted-average units - dilutive	13,990,137			12,219,699

Basic earnings per unit:
Net (loss) income per unit	$	0.19		$	(0.72	)
Dilutive earnings per unit:
Net loss per unit	$	(0.14	)	$	(0.72	)

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Subordinated Units	Three Months Ended September 30, 2013			Nine Months Ended September 30, 2013
Interest in net loss	$	(2,340	)	$	(8,782	)
Weighted-average units - basic	12,213,713			12,213,713
Effect of dilutive units (2)	—			—
Weighted-average units - dilutive	12,213,713			12,213,713

Basic and diluted net loss per subordinated unit	$	(0.19	)	$	(0.72	)

(1) The valuation adjustment to maximum redemption value of the Series A Preferred Units as of September 30, 2013 increased income available to common units in the calculation of earnings per unit (See Note 11) for the three months ended September 30, 2013. There is no valuation adjustment to maximum redemption value for the Series A Preferred Units as of September 30, 2013 in the calculation of earnings per unit (See Note 11) for the nine months ended September 30, 2013.

(2) Because we had a net loss for the nine months ended September 30, 2013 for the common units and the three and nine months ended September 30, 2013 for the subordinated units, the effect of the dilutive units would be anti-dilutive to the per unit calculation. Therefore, the weighted average units outstanding are the same for basic and dilutive net loss per unit. The weighted average units included in the computation of diluted per unit amounts were 27,972 unvested awards granted under our long-term incentive plan (See Note 13) and 1,739,473 Series A Preferred Units (See Note 11) for the three months ended September 30, 2013. The weighted average units that were not included in the computation of diluted per unit amounts were 20,221 unvested awards granted under our long-term incentive plan and 1,052,329 Series A Preferred Units for the nine months ended September 30, 2013. Diluted net income per limited partner unit reflects the potential dilution that could occur if securities or agreements to issue common units, such as awards under the long-term incentive plan, were exercised, settled or converted into common units. When it is determined that potential common units resulting from an award should be included in the diluted net income per limited partner unit calculation, the impact is reflected by applying the treasury stock method.

Distributions

Our Second Amended and Restated Agreement of Limited Partnership (“Partnership Agreement”) requires that, within 45 days after the end of each quarter we distribute all of our available cash to unitholders of record on the applicable record date, as determined by our General Partner. Currently, our Amended Credit Facility (see Note 5) restricts distributions to our unitholders to our established minimum quarterly distribution of $0.40 per unit until the Target Leverage Ratio (see Note 5) has been met.

Series A Preferred Units

During the second quarter of 2013, we raised $40.0 million of equity through issuances of 1,715,000 Series A Preferred Units and an additional General Partner contribution 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 terms 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. In-kind distributions will be 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 to 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.

The Series A Preferred Units are considered participating securities for purposes of the basic earnings per unit calculation during periods in which they receive cash distributions. As we are required to pay in-kind distributions for the first four full quarters and continuing until the Target Leverage Option (See Note 5) has been achieved, the Series A Preferred Units have been excluded from the basic earnings per unit calculation for the three and nine months ended September 30, 2013.

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The following table represents the paid in-kind (“PIK”) distribution for the period ended June 30, 2013 and the PIK distribution earned for the period ended September 30, 2013 (in thousands, except per unit and in-kind distribution units):



Payment Date	Attributable to the Quarter Ended	Per Unit Distribution			In-Kind Series A Preferred Unit Distributions to Series A Preferred Holders	In-Kind Series A Preferred Distributions Value(3)		In-Kind Unit Distribution to General Partner	In-Kind General Partner Distribution Value(3)
2013
November 14, 2013	September 30, 2013	$	0.40		30,439	$	696	621	$	14
August 14, 2013	June 30, 2013	0.35		(1)	22,276	509		455	10
August 14, 2013	June 30, 2013	0.20		(2)	2,199	50		45	1

(1) Per unit distribution of $0.35 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 issuance of 1,466,325 Series A Preferred Units and 29,925 general partner units on April 12, 2013.

(2) Per unit distribution of $0.20 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 issuance of 248,675 Series A Preferred Units and 5,075 general partner units on May 15, 2013.

(3) The value was calculated based on the Series A Preferred Units issue price of $22.86 as stated in our Partnership Agreement, multiplied by the number of units distributed.

Common Units

The following table represents our distribution declared for the period ended September 30, 2013 and distributions paid for the periods ended June 30, 2013, March 31, 2013 and 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
November 14, 2013	September 30, 2013	$	0.40			$	4,888	$	4,885	$	214	$	9,987
August 14, 2013	June 30, 2013	0.35		(1	)	—		—		10		10
August 14, 2013	June 30, 2013	0.20		(2	)	—		—		1		1
August 14, 2013	June 30, 2013	0.40				4,890		4,886		199		9,975
May 15, 2013	March 31, 2013	0.40				4,888		4,886		199		9,973
2012
February 14, 2013	December 31, 2012	0.24		(3	)	2,931		2,931		120		5,982

(3) 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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Earnings Per Common Unit of Southcross Energy LLC

The following is a reconciliation of net income per common unit used in the basic and diluted earnings per unit calculations for the three and nine months ended September 30, 2012 (in thousands, except unit and per unit data):



	Three Months Ended September 30, 2012			Nine Months Ended September 30, 2012
Net loss attributable to Southcross Energy LLC common unitholders	$	(12,241	)	$	(15,014	)
Weighted-average common units outstanding - basic	1,213,496			1,214,321
Effect of unvested common units	129,210			165,276
Weighted-average common units outstanding - diluted	$	1,342,706		$	1,379,597

Basic and diluted net loss per Southcross Energy LLC common unit	$	(10.09	)	$	(12.36	)

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). The weighted average number of unvested units that would be included in the computation of diluted earnings per unit was 129,210 and 165,276 units for the three and nine months ended September 30, 2012, respectively. Because we had a net loss for the three and nine months ended September 30, 2012, the unvested units were anti-dilutive. Therefore, the weighted average units outstanding are the same for basic and diluted net loss per common unit.

4. FINANCIAL INSTRUMENTS

Cash and Cash Equivalents, Accounts Receivable and Accounts Payable

As of September 30, 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 the debt funded through our Credit Facility executed in 2012 approximates its carrying amount as of September 30, 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. The fair value of the debt is considered a Level 2 fair value measurement.

Derivatives

Interest Rate Swaps

We manage a portion of our interest rate risk through interest rate swaps. 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%. As of September 30, 2013 and December 31, 2012, the current portion of the interest rate swap liability of $0.4 million and $0.3 million, respectively, was included within other current liabilities. As of December 31, 2012, the non-current portion of the interest rate swap liability of $0.3 million was included within other non-current liabilities. As of September 30, 2013, there was no non-current portion of the interest rate swap liability.

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



	Fair value measurement as of
	September 30, 2013		December 31, 2012
	Significant Other Observable Inputs (Level 2)
Interest rate swap liabilities	$	368	$	638

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 gain/(loss) and recognized in interest expense as the underlying hedged transactions (interest payments) are recorded. Any hedge ineffectiveness is

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recognized in interest expense immediately. We did not have any hedge ineffectiveness during the three and nine months ended September 30, 2013 and 2012.

The effect of the interest rate swap designated as a cash flow hedge in our statements of changes in partners’ capital and members’ equity and comprehensive income/(loss) were as follows (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Change in value recognized in other comprehensive loss - effective portion	$	(82	)	$	(379	)	$	(112	)	$	(728	)
Loss reclassified from accumulated other comprehensive loss to interest expense	$	108		$	84		$	302		$	169

Based on current interest rates, we estimate that approximately $0.4 million of hedging losses related to the interest rate swap contract will be reclassified from accumulated other comprehensive income/(loss) to interest expense within the next 12 months.

On an ongoing basis, a derivative instrument designated as a cash flow hedge must be highly effective in offsetting changes in cash flows of the hedged item. If it is determined that the derivative instrument is not highly effective as a hedge, hedge accounting will be discontinued prospectively. Changes in fair value of the associated hedging instrument are then recognized immediately in earnings for the remainder of the contract term unless a new hedging relationship is designated. The assessment of effectiveness excludes counterparty default risk and our own non-performance risk. The effect of these valuation adjustments was immaterial for the three and nine months ended September 30, 2013 and 2012, respectively.

If it becomes probable that a forecasted transaction (future interest payments) will not occur by the end of the originally specified time period, hedge accounting will be discontinued and the related deferred gains or losses will be recognized in our results of operations immediately. There were no amounts of gains or losses reclassified into earnings as a result of the discontinuance of cash flow hedge accounting due to the lack of probability of the forecasted transaction occurring.

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Unrealized loss on interest rate cap	$	—	$	—	$	—	$	222
Realized loss on interest rate cap	$	27	$	—	$	81	$	—

Commodity Swaps

In our normal course of business, periodically we enter into month-ahead swap contracts to hedge our exposure to certain intra-month natural gas index pricing risk. The total volume of outstanding month ahead swap contracts as of September 30, 2013 was 25,000 MMBtu per day. We had no outstanding month-ahead swap contracts as of December 31, 2012. We define these contracts as Level 2 because the index price associated with such contracts is observable and tied to a similarly quoted first-of-the-month natural gas index price. The fair value of such contracts was immaterial as of September 30, 2013.

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



	Three Months Ended September 30,					Nine Months Ended September 30,
	2013			2012		2013			2012
Realized gain/(loss) on derivatives	$	(93	)	$	144	$	(149	)	$	105

5. LONG-TERM DEBT

Credit Facility

In connection with the closing of the IPO, we 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.

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We may utilize the Credit Facility for working capital requirements and capital expenditures, the purchase of assets, the payment of distributions and other general purposes within the limitations established by the Second Amendment (as defined and described below). The Credit Facility matures on November 7, 2017, the fifth anniversary of the IPO closing date.

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 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. Pursuant to the First Amendment, we were allowed to pay our quarterly cash distribution of available cash for the first quarter of 2013 regardless of whether we met 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. In connection with the First Amendment, we incurred $0.6 million in fees, which have been deferred and are being 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 by the First Amendment and the Second Amendment, the “Amended Credit Facility”), which waived our defaults relating to financial covenants in the Credit Facility for the period ended 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 and elected at our option (the “Target Leverage Option”). Our available credit, excluding our letters of credit, continues to be subject to the availability limits described in the First Amendment. In connection with the Second Amendment, we incurred $1.5 million in fees, which have been deferred and are being amortized over the remaining life of the Credit Facility.

As a condition to the Second Amendment, Southcross Energy LLC and our General Partner deposited $34.2 million into the Collateral Account. The $34.2 million was then utilized to purchase Series A Preferred Units as described below. Additionally, Southcross Energy LLC and our General Partner agreed to deposit into the Collateral Account proceeds received from cash distributions on our common units and subordinated units that they own and that are attributable to each calendar quarter in 2013. On May 15, 2013, Southcross Energy LLC and our General Partner deposited their first quarter cash distribution of $5.8 million into the Collateral Account.

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


•	an increase in our letters of credit sublimit 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 last three quarters of 2013 and an additional $25.0 million for the subsequent 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 subsequent 18-months ending June 30, 2015);


•	distributions to our unitholders are effectively limited to our established minimum quarterly distribution of $0.40 per unit; and


•	our ability to make acquisitions is limited; and


•	once we achieve the Target Leverage Ratio, we have the option to revert the Amended Credit Facility back to the terms of our original Credit Facility.

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Pursuant to the Second Amendment, during the second quarter of 2013, our General Partner and Southcross Energy LLC made an equity investment in us in an aggregate amount equal to $40.0 million in exchange for 35,000 General Partner units and 1,715,000 Series A Preferred Units, respectively, which distributions on such securities are required to be paid-in kind for the first four full quarters following the issuance of the units and until the Target Leverage Test has been satisfied. Our total capital infusion of $40.0 million from all sales of Series A Preferred Units and General Partner contributions (See Note 11) was used to reduce borrowings under our Amended Credit Facility.

The Amended Credit Facility provides that if we fail to comply with the financial covenants of the Amended Credit Facility for the calendar quarters ending on or before December 31, 2013, we have the right (which cannot be exercised more than two times) to cure the failure to comply by having Southcross Energy LLC and/or our General Partner deposit into the Collateral Account the amount required to cure as determined by the Second Amendment.

For the quarter ended June 30, 2013, the Second Amendment required us to have Consolidated EBITDA (as defined in the Credit Facility) of at least $9.0 million, and we were not subject to the Adjusted Consolidated Total Leverage Ratio (as defined in the Credit Facility) for such quarter. As a result of our not meeting the Consolidated EBITDA covenant for the quarter ended June 30, 2013 we utilized our right to cure and Southcross Energy LLC deposited approximately $2.7 million into the Collateral Account on August 6, 2013, which was earlier than the date required under the Second Amendment.

For the quarter ended September 30, 2013, the Second Amendment requires us to have an Adjusted Consolidated Total Leverage Ratio not to exceed 7.25 to 1.00. Our Adjusted Consolidated Total Leverage Ratio for the quarter ended September 30, 2013 was approximately 6.5 to 1.00. We will not need to utilize our right to cure for the quarter ended September 30, 2013. For the fourth quarter of 2013, we have one additional right to cure.

Our ability to fund expansion projects while the Amended Credit Facility is in effect is limited to $25.0 million during the second through fourth quarters of 2013 and an additional $25.0 million in the subsequent 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. In October 2013, Southcross Energy LLC deposited an additional $3.0 million into the Collateral Account increasing our limit for 2013 expansion projects to $28.0 million.

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 our Consolidated Total Funded Indebtedness (as defined in the Credit Facility) with amounts on deposit in the Collateral Account, and our Adjusted Consolidated Total Leverage Ratio is not to exceed the ratios set forth below for the corresponding periods:



		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

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 invested in us as additional paid-in kind 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 us to increase the amount of our capital expenditures) will be released to Southcross Energy LLC and our General Partner.

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The Second Amendment provides that upon satisfying the Target Leverage Ratio we will not permit our Maximum Consolidated Total Leverage Ratio to exceed the ratio set forth below for the corresponding period:



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

As of September 30, 2013, we have not satisfied the Target Leverage Ratio, therefore the Maximum Consolidated Total Leverage Ratio is not applicable.

The Second Amendment changed the minimum Consolidated Interest Coverage Ratio (as provided in the Amended Credit Facility) 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. For the quarter ended September 30, 2013, our consolidated interest coverage ratio was approximately 2.8.

Borrowings under the Amended 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 Amended Credit Facility, the applicable margin under LIBOR borrowings was 4.50% at September 30, 2013. The weighted-average interest rate for the three and nine months ended September 30, 2013 was 4.80% and 4.33%, respectively.

Under our Amended Credit Facility, we have the ability to borrow $250.0 million plus an amount equal to the funds deposited into the Collateral Account and letters of credit outstanding. As of September 30, 2013, cash on deposit in the Collateral Account was $8.5 million. As of September 30, 2013, our borrowings under the Amended Credit Facility were $258.5 million, and our remaining available capacity under the Amended Credit Facility was $28.7 thousand. As of September 30, 2013, Southcross Energy LLC had $33.1 million of cash which has been made available for deposit into the Collateral Account to support subsequent additional borrowings. For the three and nine months ended September 30, 2013 our average outstanding borrowings were $254.2 million and $238.9 million, respectively, and for the three and nine months ended September 30, 2013 our maximum outstanding borrowings were $258.5 million.

6. PROPERTY, PLANT AND EQUIPMENT

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



	Estimated Useful Life (yrs)	September 30, 2013			December 31, 2012
Pipelines	30	$	339,925		$	250,177
Gas processing, treating and other plants	15	243,891			221,594
Compressors	7	20,030			19,241
Rights of way and easements	15	20,729			20,729
Furniture, fixtures and equipment	5	3,293			3,087
Capital lease vehicles	3-5	1,399			—
Total property, plant and equipment		629,267			514,828
Accumulated depreciation and amortization		(71,282		)	(46,466		)
Total		557,985			468,362
Construction in progress		15,758			77,011
Land and other		5,308			5,230
Property, plant and equipment, net		$	579,051		$	550,603

Depreciation is provided using the straight-line method based on the estimated useful life of each asset. Depreciation expense for the three and nine months ended September 30, 2013 was $9.4 million and $25.0 million, respectively, including $1.3 million in accelerated depreciation during the three months ended September 30, 2013 for the planned abandonment at one of our compressor stations. Depreciation expense for the three and nine months ended September 30, 2012 was $5.5 million and $12.9 million, respectively.

Costs related to projects under construction, including interest on funds borrowed to finance the construction of facilities, are capitalized as construction in progress. For the three and nine months ended September 30, 2013, we capitalized interest of

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$0.3 million and $1.3 million, respectively. For the three and nine months ended September 30, 2012, we capitalized interest of $2.2 million and $4.5 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 $3.9 million to return the plant to service and filed an insurance claim related to these costs. We recovered $1.0 million from insurance for this loss during the second quarter of 2013 and believe it is probable that we will recover the remaining costs, less a $0.3 million deductible, under our insurance policies.

7. OTHER ASSETS

Other assets consisted of the following (in thousands):



	September 30, 2013		December 31, 2012
Deferred financing costs	$	5,577	$	4,385
Prepaid expenses	605		551
Other	201		195
Total other assets	$	6,383	$	5,131

We incurred 2.1 million in costs in connection with the First Amendment and Second Amendment entered into during the nine months ended September 30, 2013. We incurred $5.2 million in costs as a result of entering into amendments to our (and our predecessor’s) credit agreements during the nine months ended September 30, 2012.

Deferred financing costs are amortized over the life of the Credit Facility. Amortization of deferred financing costs recorded in interest expense were as follows (in thousands):



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Amortization of deferred financing costs	$	345	$	322	$	947	$	948

8. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

Trade accounts payable as of September 30, 2013 and December 31, 2012 included $6.5 million and $40.7 million, respectively, related to capital expenditures. These amounts have been reflected as non-cash investing activities within the condensed consolidated statements of cash flows.

9. COMMITMENTS AND CONTINGENCIES

Legal Matters

On March 5, 2013, our subsidiary 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 and sales contract between the parties. Formosa filed a response generally denying our claims and, later, Formosa filed a counterclaim against our subsidiary claiming our affiliate breached the gas processing and sales contract and a related agreement between the parties for the supply by Formosa of residue gas to a third party on behalf of our subsidiary. We believe the counterclaims are without merit and our subsidiary will defend itself vigorously against the counterclaims while continuing to pursue its own claims. We cannot predict the outcome of such litigation or the timing of any related recoveries or payments.

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 currently are 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 ultimately will have a material effect on our results of operations, cash flows or financial condition in any future reporting periods.

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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.

Capital Leases

We have auto leases classified as capital leases that are recorded in other current liabilities and other non-current liabilities in our consolidated balance sheet as of September 30, 2013. The lease termination dates of the agreements vary from 2013 until 2017. We recorded amortization expense related to the capital leases of $0.1 million and $0.4 million for the three and nine months ended September 30, 2013, respectively. We had no capital leases during 2012. Future minimum annual rental commitments under our capital leases as of September 30, 2013, were as follows (in thousands):



Fiscal Year	Capital Leases
2013 (remaining)	$	144
2014	516
2015	291
2016	99
2017	28
Total future payments	1,078
Less: Imputed interest	(46		)
Future lease payments	$	1,032

Capital leases entered into during the three and nine months ended September 30, 2013 were $0.2 million and $1.4 million, respectively.

Operating Leases

We maintain operating leases in the ordinary course of business activities. These leases include those for office and other operating facilities and equipment. The lease termination dates of the agreements vary from 2013 to 2017. Future minimum annual rental commitments under our operating leases as of September 30, 2013 were as follows (in thousands):



Fiscal Year	Operating Leases
2013 (remaining)	$	150
2014	578
2015	539
2016	436
2017	294
Future lease payments	$	1,997

Expenses associated with operating leases were $0.4 million and $1.1 million for the three and nine months ended September 30, 2013, respectively. Expenses associated with operating leases were $0.6 million and $1.6 million for the three and nine months ended September 30, 2012, respectively.

Purchase Commitments

At September 30, 2013, we had commitments of approximately $1.6 million to purchase equipment related to our capital projects.

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10. TRANSACTIONS WITH RELATED PARTIES

Charlesbank

Before our IPO, Charlesbank provided certain management services to Southcross Energy LLC pursuant to a management services agreement (the “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 and we did not incur management fees thereafter. For the three and nine months ended September 30, 2012, Southcross Energy LLC incurred management fees of $0.2 million and $0.5 million, respectively, for services received under the Charlesbank Agreement.

The current board of directors of our General Partner includes three persons affiliated with Charlesbank and three outside directors. All of these directors are compensated equally for similar responsibilities and reimbursed for expenses incurred for their services to us. For the three and nine months ended September 30, 2013, we paid fees related to the Charlesbank director services of $0.1 million and $0.4 million, respectively, which are reflected in general and administrative expenses in our consolidated statements of operations.

Southcross Energy Partners GP, LLC (our General Partner)

Our General Partner does not receive a management fee or other compensation for its management of us. However, our General Partner and its affiliates are entitled to reimbursements for all expenses incurred on our behalf, including, among other items, compensation expense for all employees required to manage and operate our business. During the three and nine months ended September 30, 2013, we incurred expenses of $6.8 million and $18.9 million, respectively, related to these reimbursements, which are reflected in operating expenses in our consolidated statements of operations.

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

During the second quarter of 2013, to satisfy our requirements under our Amended Credit Facility, we entered into a Purchase Agreement (as defined below) with Southcross Energy LLC, pursuant to which we issued and sold 1,715,000 Series A Preferred Units to Southcross Energy LLC for a cash purchase price of $22.86 per Series A Preferred Unit, in a privately negotiated transaction (See Note 11). After the Series A Preferred Units issuance during the second quarter of 2013, Southcross Energy LLC sold 1,500,000 of the units to third parties. Southcross Energy LLC currently holds 218,068 Series A Preferred Units. See Note 5 for discussion of the Collateral Account held by our General Partner. See Note 5 for discussion of the Collateral Account held by our General Partner and cash made available for deposit by Southcross Energy LLC.

11. SERIES A PREFERRED UNITS

We entered into a Series A Convertible Preferred Unit Purchase Agreement (the “Purchase Agreement”) with Southcross Energy LLC, pursuant to which we issued and sold 1,715,000 Series A Preferred Units to Southcross Energy LLC during the second quarter of 2013 for a cash purchase price of $22.86 per unit, in a privately negotiated transaction (the “Private Placement”). Southcross Energy LLC sold 1,500,000 of these Series A Preferred Units to third parties during the second quarter of 2013.

Our total capital infusion of $40.0 million, from all sales of Series A Preferred Units and General Partner capital contributions, was used to reduce borrowings under our Amended Credit Facility (See Note 5). The Private Placement of Series A Preferred Units resulted in proceeds to us of $39.2 million. We also received a $0.8 million capital contribution from our General Partner to maintain its 2.0% general partner interest in us.

Applicable accounting guidance related to the Series A Preferred Units requires that equity instruments with redemption features that are redeemable at the option of the holder be classified outside of permanent equity. The change of control rights associated with the Series A Preferred Units requires the units to be classified outside of permanent equity. The Series A Preferred Units were adjusted to maximum redemption value as of June 30, 2013 as the maximum redemption value, calculated in accordance with the change of control rights provision of our Partnership Agreement, was greater than the fair value of the units at issuance. The Series A Preferred Units have been adjusted to the fair value at issuance as of September 30, 2013 because the maximum redemption value is currently less than the fair value of the units at issuance. The decrease in the valuation adjustment to issuance value of $4.7 million and the distributions associated with the Series A Preferred Units of $0.7 million have been included in the calculation of partners’ capital and earnings per unit for the three months ended September 30, 2013. The distributions associated with the Series A Preferred Units of $1.3 million have been included in the calculation

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of partners’ capital and earnings per unit for the nine months ended September 30, 2013. Additionally, none of the identified embedded derivatives relating to the terms of the Series A Preferred Units require bifurcation, as each embedded derivative was determined to be clearly and closely related to the host contract.

Voting Rights: 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 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.

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 of those units 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 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.

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. Additionally, on the later of January 1, 2015 and the date we exercise the Target Leverage Option (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 before 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. Further, the Series A Preferred Units will be convertible into common units based on an exchange ratio 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 before January 1, 2015.

Dissolution and Liquidation: The Series A Preferred Units are senior to our common units with respect to rights on dissolution and liquidation. Common units issued upon conversion of Series A Preferred Units will rank equally with the rest of our common units with respect to rights on dissolution and liquidation.

12. 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 had 12,222,692 and 12,213,713 common units issued and outstanding as of September 30, 2013 and December 31, 2012, respectively.

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. We had 12,213,713 subordinated units issued and outstanding as of September 30, 2013 and December 31, 2012.

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General Partner Interests

Our general partner interest consisted of 534,638 general partner units as of September 30, 2013 and 498,518 general partner units as of December 31, 2012. In connection with the Private Placement, our General Partner made a capital contribution in the amount of $0.8 million in exchange for an issuance of an additional 35,000 general partner units during the second quarter of 2013 to maintain its 2.0% ownership interest in us. The General Partner has received general partner unit PIK distributions from the general partner units purchased in connection with the Private Placement (See Note 3).

13. UNIT BASED COMPENSATION

Long-Term Incentive Plan

On November 7, 2012, and in connection with our IPO, we established a 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 or an amount of cash equal to the fair market value of a common unit at the time of vesting, as determined by management at its discretion. These awards also include distribution equivalent rights that grant the holder the right to receive an amount equal to the cash distributions on common units during the period the award remains outstanding.

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



	Nine Months Ended September 30, 2013
	Units		Weighted-average fair value at grant date
Unvested - December 31, 2012	144,500		$	23.01
Granted units	110,279		$	22.00
Forfeited units	(13,200	)	$	22.53
Vested units	(8,979	)	$	19.83
Unvested - September 30, 2013	232,600		$	22.56

We granted awards under the Incentive Plan, which we have classified as equity awards, with a grant date fair value of $2.4 million for the nine months ended September 30, 2013. As of September 30, 2013, we had total unamortized compensation expense of $4.1 million related to these awards, which we expect to be amortized over the three-year vesting period from each equity award’s grant date. As of September 30, 2013, we had 1,508,421 units available for issuance under the Incentive Plan.

Unit Based Compensation Expense

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Unit-based compensation	$	552	$	147	$	1,645	$	293

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14. REVENUES

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Sales of natural gas	$	99,483	$	80,290	$	304,343	$	217,484
Sales of NGLs and condensate	45,916		26,487		112,128		94,133
Transportation, gathering and processing fees	15,124		11,290		42,644		32,573
Other	106		83		468		279
Total revenues	$	160,629	$	118,150	$	459,583	$	344,469

15. CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE

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

Our top ten customers for the three and nine months ended September 30, 2013 and 2012 represent the following percentages of consolidated revenue:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Top 10 customers	69.1	%	59.0	%	58.8	%	66.0	%

The percentage of total consolidated revenue for each customer that exceeded 10% of total revenues for the three and nine months ended September 30, 2013 and 2012 was as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Sherwin Alumina Company	12.0	%	12.2	%	12.3	%	10.8	%
Trafigura AG	13.1	%	(a)		(a)		(a)
Formosa Hydrocarbons Co., Inc.	(a),(b)		16.3	%	(a),(b)		24.8	%

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

(b) Our contract with Formosa terminated on June 1, 2013.

For the nine months ended September 30, 2013 and 2012, we did not experience significant non-payment for services. At September 30, 2013, we did not record an allowance for uncollectible accounts receivable.

16. SUBSEQUENT EVENTS

Partnership Distribution

On October 21, 2013, we declared a cash distribution of $0.40 per common unit and subordinated unit, including units equivalent to our General Partner’s two percent interest in the Partnership, which will be paid on November 14, 2013 to unitholders of record on November 7, 2013. Also on October 21, 2013, we declared a Series A Preferred Unit distribution of $0.40 per unit, which will be paid in-kind on November 14, 2013 to unitholders of record on November 7, 2013, and our General Partner will receive a number of general partner units to maintain the General Partner’s two percent interest in the Partnership.

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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 LLC was formed in 2009 and is our predecessor. In connection with our initial public offering of common units (“IPO”) on November 7, 2012, 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 our holding company. 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”), all of our subordinated units, as well as a portion of our common units outstanding and our Series A Convertible Preferred Units (“Series A Preferred Units”) originally issued during the second quarter of 2013 (See Part I, Item 1, Note 11, “Series A Preferred Units”). 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.

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 purity product NGLs to various industrial and energy markets as well as large pipeline systems. Through our network of pipelines, we connect supplies of natural gas to our customers, which include industrial, commercial and power generation customers and local distribution companies.

Our results are determined primarily by the volumes of natural gas we gather and process, the efficiency of our processing plants and NGL fractionation plants, the commercial terms of our contractual arrangements, natural gas and NGL prices, and our operations and maintenance expense. We manage our business with the goal to maximize the gross operating margin we earn from contracts balanced against any risks we assume in our contracts. Our contracts vary in duration from one month to 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 to provide service to our customers. We purchase, gather, process, treat, compress, transport and sell natural gas and purchase, fractionate, transport and sell NGLs. Contracts with a counterparty generally contain one or more of the following arrangements:


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

•

Fixed-Spread. Under these arrangements, we purchase natural gas and NGLs from producers or suppliers at receipt points on our systems at an index price plus or minus a fixed price differential and sell these volumes of natural gas and NGLs at delivery points off our systems at the same index price, plus or minus a fixed price differential. By entering into such back-to-back purchases and sales, we are able to mitigate our risk associated with changes in the general commodity price levels of natural gas and NGLs. We remain subject to variations in our fixed-spreads to the extent we are unable to 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

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

We assess gross operating margin opportunities across our integrated value stream, so that processing margins may be supplemented by gathering and transportation fees and opportunities to sell residue gas and NGLs at fixed-spreads. Gross operating margin earned under fixed-fee and fixed-spread arrangements is directly related to the volume of natural gas that flows through our systems and is generally independent from general commodity price levels. A sustained decline in commodity prices could result in a decline in volumes entering our system and, thus, a decrease in gross operating margin for our fixed-fee and fixed-spread arrangements.

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



	Three Months Ended September 30,									Nine Months Ended September 30,
	2013				2012					2013				2012
	Gross margin		Percent of total gross operating margin		Gross margin			Percent of total gross operating margin		Gross margin		Percent of total gross operating margin		Gross margin		Percent of total gross operating margin
Fixed-fee	$	15,104	59.9	%	$	11,732		77.8	%	$	42,748	65.4	%	$	34,110	61.8	%
Fixed-spread	2,311		9.2	%	5,690			37.8	%	10,821		16.5	%	16,867		30.6	%
Sub-total	17,415		69.1	%	17,422			115.6	%	53,569		81.9	%	50,977		92.4	%
Commodity-sensitive	7,798		30.9	%	(2,345		)	(15.6	)%	11,802		18.1	%	4,215		7.6	%
Total gross operating margin	$	25,213	100.0	%	$	15,077		100.0	%	$	65,371	100.0	%	$	55,192	100.0	%

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 and our ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA and distributable cash flow are not measures calculated in accordance with GAAP.

We define Adjusted EBITDA as net income, plus interest expense, income tax expense, depreciation and amortization expense, certain non-cash charges such as non-cash equity compensation and unrealized losses on derivative contracts, and

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selected charges and transaction costs that are unusual or non-recurring, less interest income, income tax benefit, unrealized gains on 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 our indebtedness and make future cash distributions;


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


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

Non-GAAP Financial Measures

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

Reconciliations of Non-GAAP Financial Measures

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Reconciliation of gross operating margin to net (loss) income
Gross operating margin	$	25,213		$	15,077		$	65,371		$	55,192
(Deduct):
Income tax expense	(125		)	7			(404		)	(249		)
Interest expense	(3,587		)	(1,362		)	(8,735		)	(4,493		)
General and administrative expense	(5,227		)	(3,351		)	(16,850		)	(8,987		)
Depreciation and amortization expense	(9,447		)	(5,522		)	(24,958		)	(12,860		)
Operations and maintenance expense	(10,896		)	(8,890		)	(31,069		)	(24,469		)
Net (loss) income	$	(4,069	)	$	(4,041	)	$	(16,645	)	$	4,134

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Reconciliation of Net Cash Flows Provided by Operating Activities to Net Income and Adjusted EBITDA
Net cash provided by operating activities	$	3,798		$	2,818		$	3,462		$	15,062
Add (deduct):
Depreciation and amortization expense	(9,447		)	(5,522		)	(24,958		)	(12,860		)
Unit-based compensation	(552		)	(146		)	(1,645		)	(293		)
Deferred financing costs amortization	(345		)	(322		)	(947		)	(948		)
Unrealized loss	—			—			—			(222		)
Other, net	81			—			63			—
Changes in operating assets and liabilities:										—
Trade accounts receivable	3,541			13,064			1,191			2,292
Prepaid expenses and other	1,158			815			335			198
Other non-current assets	(8		)	407			60			1,598
Accounts payable and accrued expenses	378			(12,901		)	7,502			166
Interest payable	—			(76		)	—			(75		)
Other liabilities	(2,673		)	(2,178		)	(1,708		)	(784		)
Net (loss) income	$	(4,069	)	$	(4,041	)	$	(16,645	)	$	4,134
Add:
Depreciation and amortization expense	$	9,447		$	5,522		$	24,958		$	12,860
Interest expense, net	3,587			1,362			8,735			4,493
Unit-based compensation	552			146			1,645			293
Income tax expense	125			(7		)	404			249
Other, net	20			—			38			222
Expenses associated with significant items	—			—			1,314			—
Adjusted EBITDA	$	9,662		$	2,982		$	20,449		$	22,251
(Deduct):
Cash interest, net of capitalized costs	$	(3,231	)	$	(943	)	$	(7,756	)	$	(3,128	)
Income tax expense	(125		)	7			(404		)	(249		)
Maintenance capital expenditures	(706		)	(1,047		)	(2,057		)	(2,784		)
Distributable cash flow	$	5,600		$	999		$	10,232		$	16,090

Current Year Highlights

The following events took place during the nine months ended September 30, 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 (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 by the First Amendment and the Second Amendment, the “Amended Credit Facility”), which waived our defaults under the Credit Facility relating to financial covenants for the period ended 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 Part I, Item 1, Note 5, “Long-Term Debt” of this report.

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Series A Preferred Units

During the second quarter of 2013, to satisfy our requirements under our Amended Credit Facility, we entered into a Purchase Agreement (as defined below) with Southcross Energy LLC, pursuant to which we issued and sold 1,715,000 Series A Preferred Units to Southcross Energy LLC for a cash purchase price of $22.86 per Series A Preferred Unit, in a privately negotiated transaction. After the Series A Preferred Units issuance during the second quarter of 2013, Southcross Energy LLC sold 1,500,000 of the units to third parties. Southcross Energy LLC currently holds 218,068 Series A Preferred Units. See further discussion included in Part I, Item 1. Note 11, “Series A Preferred Units” of this report.

Key Factors Affecting Operating Results and Financial Condition


•	Bonnie View NGL fractionation facility. In February 2013, we completed the expansion of NGL fractionation 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 production of off-specification NGLs. This continued into the six month period ended June 30, 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. 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 approximately 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 that damaged a small portion of the facility. We resumed significant operations in April 2013 and full operations in May 2013. In connection with the fire, we spent $3.9 million to return the plant to service and filed an insurance claim related to these costs. We recovered $1.0 million from insurance for this loss during the second quarter of 2013 and believe it is probable that we will recover the remaining costs, less a $0.3 million deductible, under our insurance policies.


•	New long-term NGL sales contracts. 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 began in May 2013, providing us with additional markets at fixed differentials to NGL index prices and enhancing our earnings.


•	June plant outage. During June 2013, the Bonnie View fractionator experienced a non-reportable release of process oil within the facility. Shutdown of the facility to make modifications and perform safety reviews lasted four days and resulted in approximately $1.5 million of lost margin and increased operating expenses.

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Results of Operations

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Revenues	$	160,629		$	118,150		$	459,583		$	344,469
Expenses:
Cost of natural gas and liquids sold	135,416			103,073			394,212			289,277
Operations and maintenance	10,896			8,890			31,069			24,469
Depreciation and amortization	9,447			5,522			24,958			12,860
General and administrative	5,227			3,351			16,850			8,987
Total expenses	160,986			120,836			467,089			335,593

(Loss) income from operations	(357		)	(2,686		)	(7,506		)	8,876
Interest expense, net	(3,587		)	(1,362		)	(8,735		)	(4,493		)
(Loss) income before income tax expense	(3,944		)	(4,048		)	(16,241		)	4,383
Income tax expense	(125		)	7			(404		)	(249		)
Net (loss) income	$	(4,069	)	$	(4,041	)	$	(16,645	)	$	4,134

Other financial data:
Adjusted EBITDA	$	9,662		$	2,982		$	20,449		$	22,251
Gross operating margin	$	25,213		$	15,077		$	65,371		$	55,192

Maintenance capital expenditures	$	706		$	1,047		$	2,057		$	2,784
Expansion capital expenditures	$	15,988		$	39,799		$	84,092		$	109,666

Operating data:
Average throughput of gas (MMBtu/d)	582,056			538,990			576,565			551,352
Average volume of processed gas (MMBtu/d)	236,991			166,140			231,344			179,590
Average volume of NGLs sold (Bbls/d)	12,808			8,336			11,243			8,774

Realized prices on natural gas volumes ($/MMBtu)	$	3.67		$	2.89		$	3.76		$	2.62
Realized prices on NGL volumes ($/gal)	$	0.93		$	0.82		$	0.87		$	0.93

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



	Three Months Ended September 30,		Nine Months Ended September 30,
	2013	2012	2013	2012
Average throughput volumes of natural gas (MMBtu/d)
South Texas	379,878	340,965	377,816	348,614
Mississippi/Alabama	202,178	198,025	198,749	202,738
Total average throughput volumes of natural gas	582,056	538,990	576,565	551,352
Average volume of processed gas (MMBtu/d)	236,991	166,140	231,344	179,590
Average volume of NGLs sold (Bbls/d)	12,808	8,336	11,243	8,774

Three Months Ended September 30, 2013 Compared to Three Months Ended September 30, 2012

Volume and overview. Our average volume of natural gas per day increased 8% to 582,056 MMBtu/d during the three months ended September 30, 2013, compared to 538,990 MMBtu/d during the three months ended September 30, 2012, due primarily to increased rich gas volumes entering our pipelines in South Texas to be processed at our facilities. Processed gas

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volumes increased 43% to 236,991 MMBtu/d during the three months ended September 30, 2013, compared to 166,140 MMBtu/d during the three months ended September 30, 2012.

The average volume of NGLs produced for the three months ended September 30, 2013 was 12,808 Bbls/d, an increase of 54%, compared to 8,336 Bbls/d for the three months ended September 30, 2012. This increase was due primarily to the impact of increased volumes of rich gas processed at our facilities.

Gross operating margin for the three months ended September 30, 2013 was $25.2 million, compared to $15.1 million for the three months ended September 30, 2012. This increase of 67% was due primarily to increased processed gas volumes and increased transportation, gathering and processing fees.

Adjusted EBITDA increased by 224% to $9.7 million for the three months ended September 30, 2013, compared to $3.0 million for the three months ended September 30, 2012, due to higher volumes and margins from processing and fractionation activities partially offset by higher operating and general and administrative expenses. We had a net loss of $4.1 million for the three months ended September 30, 2013 compared to net loss of $4.0 million for the three months ended September 30, 2012. Net income declined due to higher depreciation and amortization expense and interest expense.

Revenues. Our total revenues for the three months ended September 30, 2013 were $160.6 million, compared to $118.2 million for the three months ended September 30, 2012. This increase of $42.5 million, or 36%, was due primarily to increased revenue from sales of NGLs and condensate to $45.9 million for the three months ended September 30, 2013 compared to $26.5 million for the three months ended September 30, 2012. The increase was due to higher NGL volumes delivered to our processing plants and higher NGL prices. Additionally, revenue from sales of natural gas increased by $19.2 million, to $99.5 million for the three months ended September 30, 2013 compared to $80.3 million for the three months ended September 30, 2012 from an increase in natural gas sales volumes. Revenue from transportation, gathering and processing fees increased by $3.8 million or 34% for the three months ended September 30, 2013 compared to the same period in 2012, reflecting the results of additional rich gas volumes in 2013. Realized average natural gas and NGL prices were as follows:



	Three Months Ended September 30,
	2013	2012
Natural Gas	$3.67/MMBtu	$2.89/MMBtu
NGLs	$0.93/gal	$0.82/gal

Cost of natural gas and NGLs sold. Our cost of natural gas and NGLs sold for the three months ended September 30, 2013 was $135.4 million, compared to $103.1 million for the three months ended September 30, 2012. This increase of $32.3 million, or 31%, was due primarily to higher realized natural gas prices and increased natural gas volumes purchased, as well as increased NGL volumes purchased and higher realized NGL prices compared to the same period in 2012.

Operations and maintenance expense. Operations and maintenance expense for the three months ended September 30, 2013 was $10.9 million, compared to $8.9 million for the three months ended September 30, 2012. This increase of $2.0 million, or 23%, was related primarily to the cost of operating the Bonnie View fractionation facility and the Woodsboro plant for the three months ended September 30, 2013, as Bonnie View commenced operations in the fourth quarter of 2012 and Woodsboro had higher processing volumes for the three months ended September 30, 2013 compared to the three months ended September 30, 2012.

General and administrative (“G&A”) expenses. G&A expenses for the three months ended September 30, 2013 were $5.2 million, compared to $3.4 million for the three months ended September 30, 2012. This increase of $1.9 million, or 56%, was due primarily to increased expenses related to additional headcount to build our corporate and support infrastructure, the expenses related to being a public company, insurance coverage to support our growing operations, and increased legal expenses associated with ongoing litigation.

Depreciation and amortization expense. Depreciation and amortization expense for the three months ended September 30, 2013 was $9.4 million, compared to $5.5 million for the three months ended September 30, 2012. The increase of $3.9 million, or 71%, was due primarily to depreciation of growth capital projects placed in service and the acceleration of $1.3 million in depreciation related to the planned abandonment of a compressor station during the third quarter of 2013.

Interest expense. For the three months ended September 30, 2013, net interest expense was $3.6 million, compared to $1.4 million for the three months ended September 30, 2012. This increase was due to higher average borrowings and an

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increase in our weighted average borrowing rate of 4.8% for the three months ended September 30, 2013 compared to 4.6% the three months ended September 30, 2012.

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

Volume and overview. Our average volume of natural gas per day increased 5% to 576,565 MMBtu/d during the nine months ended September 30, 2013, compared to 551,352 MMBtu/d during the nine months ended September 30, 2012, due primarily to increased rich gas volumes entering our pipelines in South Texas to be processed at our facilities. Processed gas volumes increased 29% to 231,344 MMBtu/d during the nine months ended September 30, 2013, compared to 179,590 MMBtu/d during the nine months ended September 30, 2012.

The average volume of NGLs produced for the nine months ended September 30, 2013 was 11,243 Bbls/d, an increase of 28%, compared to 8,774 Bbls/d for the nine months ended September 30, 2012. This increase was due to the impact of increased volumes of rich gas processed at our facilities.

Gross operating margin, for the nine months ended September 30, 2013, was $65.4 million compared to $55.2 million for the nine months ended September 30, 2012. This increase was due primarily to increased processed gas volumes and increased transportation, gathering and processing fees.

Adjusted EBITDA decreased by 8% to $20.4 million for the nine months ended September 30, 2013, compared to $22.3 million for the nine months ended September 30, 2012, due primarily to higher general and administrative expenses and operating expenses, offset by an increase in higher volumes from processing and fractionation activities. We had a net loss of $16.6 million for the nine months ended September 30, 2013 compared to net income of $4.1 million for the nine months ended September 30, 2012. Net income declined due to higher depreciation and amortization expense and interest expense.

Revenues. Our total revenues for the nine months ended September 30, 2013 were $459.6 million, compared to $344.5 million for the nine months ended September 30, 2012. This increase of $115.1 million, or 33%, was due primarily to the increase in revenue from sales of natural gas to $304.3 million for the nine months ended September 30, 2013 compared to $217.5 million for the nine months ended September 30, 2012 resulting from increased natural gas sales volumes. Revenue from sales of NGLs and condensate increased $18.0 million, or 19%, to $112.1 million for the nine months ended September 30, 2013, compared to $94.1 million for the nine months ended September 30, 2012, reflecting the benefit of new volumes delivered to our plants. Additionally, revenue from transportation, gathering and processing fees increased $10.1 million, or 31%, for the nine months ended September 30, 2013, reflecting the results of additional rich gas volumes in 2013. Realized average natural gas and NGL prices were as follows:



	Nine Months Ended September 30,
	2013	2012
Natural Gas	$3.76/MMBtu	$2.62/MMBtu
NGLs	$0.87/gal	$0.93/gal

Cost of natural gas and NGLs sold. Our cost of natural gas and NGLs sold for the nine months ended September 30, 2013 was $394.2 million, compared to $289.3 million for the nine months ended September 30, 2012. This increase of $104.9 million, or 36%, was due primarily to higher volumes of natural gas purchased compared to the same period in 2012 and increased NGL volumes partially offset by lower realized NGL prices.

Operations and maintenance expense. Operations and maintenance expense for the nine months ended September 30, 2013 was $31.1 million, compared to $24.5 million for the nine months ended September 30, 2012. This increase of $6.6 million, or 27%, was due primarily to $6.5 million in costs related to operating the Woodsboro plant and Bonnie View fractionation facility for the nine months ended September 30, 2013, as Woodsboro commenced operations in the third quarter of 2012 and Bonnie View commenced operations in the fourth quarter of 2012. In addition, we had increased ad valorem and other taxes of $1.4 million for the nine months ended September 30, 2013 due to investments in and expansion of our assets which were partially offset by a reduction of $1.3 million in operating expenses associated with the operations of our pipeline assets due to a reduction in scheduled maintenance for the nine months ended September 30, 2013.

General and administrative (“G&A”) expenses. G&A expenses for the nine months ended September 30, 2013 were $16.9 million, compared to $9.0 million for the nine months ended September 30, 2012. This increase of $7.9 million, or 87%, was due primarily to increased expenses from additional headcount at our corporate office, expenses related to being a public

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company, insurance coverage to support our growing asset base and operations, and increased legal expenses associated with ongoing litigation.

Depreciation and amortization expense. Depreciation and amortization expense for the nine months ended September 30, 2013 was $25.0 million, compared to $12.9 million for the nine months ended September 30, 2012. The increase of $12.1 million, or 94%, was due primarily to the completion of growth capital projects and the acceleration of $1.3 million in depreciation related to the planned abandonment of a compressor station during the third quarter of 2013.

Interest expense. For the nine months ended September 30, 2013, net interest expense was $8.7 million, compared to $4.5 million for the nine months ended September 30, 2012. This increase was due to higher average borrowings and interest rates associated with our borrowings of 4.3% for the nine months ended September 30, 2013 compared to 3.9% the nine months ended September 30, 2012.

Liquidity and Capital Resources

Sources of Liquidity

Our primary source of liquidity has been 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 Amended Credit Facility. 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 and construction of new assets, businesses acquisitions, and distributions to unitholders.

We expect 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. Our ability to fund expansion projects while the Amended Credit Facility is in effect is limited to $25.0 million during the second through fourth quarters of 2013 and an additional $25.0 million in the subsequent 18-month period ending June 30, 2015, which can be increased to $28.0 million if additional funds are placed into the Collateral Account (as defined in the Second Amendment). In October 2013, Southcross Energy LLC deposited an additional $3.0 million into the Collateral Account increasing our limit for 2013 to $28.0 million. See Part I, Item 1, Note 5, “Long-Term Debt” of this report for a description of the amendments to the Credit Facility.

Under our Amended Credit Facility, we have the ability to borrow $250.0 million plus an amount equal to the funds deposited into the Collateral Account and letters of credit outstanding with a maximum limit of $350.0 million. Southcross Energy LLC and our General Partner agreed to deposit into the Collateral Account proceeds received from cash distributions on our common units and subordinated units that they own and that are attributable to each calendar quarter in 2013. As of October 31, 2013, cash on deposit in the Collateral Account was $11.5 million. As of October 31, 2013, our borrowings under the Amended Credit Facility were $254.8 million, and our remaining available capacity under the Amended Credit Facility was $6.7 million. As of October 31, 2013, Southcross Energy LLC had $30.1 million of cash which has been made available for deposit into the Collateral Account to support subsequent additional borrowings.

Series A Preferred Unit issuance. We entered into a Series A Convertible Preferred Unit Purchase Agreement (the “Purchase Agreement”) with Southcross Energy LLC, pursuant to which we issued and sold 1,715,000 Series A Preferred Units to Southcross Energy LLC during the second quarter of 2013. Series A Preferred Units were sold to Southcross Energy LLC for a cash purchase price of $22.86 per unit, in a privately negotiated transaction (the “Private Placement”). Southcross Energy LLC sold 1,500,000 of these Series A Preferred Units to third parties during the second quarter of 2013.

Our total capital infusion of $40.0 million, from all sales of Series A Preferred Units and General Partner capital contributions, was used to reduce borrowings under our Amended Credit Facility (See Part I, Item 1, Note 5, “Long-Term Debt”). The Private Placement of Series A Preferred Units resulted in proceeds to us of $39.2 million, and our General Partner contributed $0.8 million to maintain its 2.0% general partner interest in us.

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


•	maintenance capital expenditures, which are capital expenditures 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 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.

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Maintenance capital	$	706	$	1,047	$	2,057	$	2,784
Growth capital	15,988		39,799		84,092		109,666
Capital expenditures	$	16,694	$	40,846	$	86,149	$	112,450

Our growth capital expenditures during the three months ended September 30, 2013 related primarily to (i) our new pipeline laterals and (ii) enhancements to our Woodsboro and Bonnie View facilities. Growth capital expenditures for the nine months ended September 30, 2013 related primarily to (i) our continued construction of the Bonnie View NGL fractionation facility completed in February 2013 and (ii) our new Bee Line pipeline completed in February 2013. Our growth capital expenditures during the three and nine months ended September 30, 2012 related primarily to (i) construction of the Bonnie View fractionation facility and (ii) construction of our Woodsboro processing facility.

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

Our ability to benefit from growth projects to accommodate strong drilling activity and the associated need for infrastructure assets and services is subject to operational risks and uncertainties such as the uncertainty inherent in some of the assumptions underlying design specifications for new, modified or expanded facilities. These risks also impact third-party service providers and their facilities. Delays or under-performance of our facilities or third-party facilities may adversely affect our ability to generate cash from operations and comply with our obligations, including the covenants under our debt instruments. For example, we encountered operational difficulties in connection with the fire at our Gregory facility that had a negative impact on our results in the nine months ended September 30, 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 our ability to comply with our debt covenants would likewise be affected adversely if we experienced declining volumes over a sustained period and/or unfavorable commodity prices.

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 in compliance with our debt covenants. During the first half of 2013, in conjunction with the additional equity investments in us, we negotiated with our lenders and secured more favorable financial covenants and amended our Credit Facility. As of October 31, 2013, we had $6.7 million of borrowing capacity under our Amended Credit Facility. We believe we have and will continue to have sufficient liquidity to operate our business due partially to a provision in our Amended Credit Facility to increase borrowing capacity by placing additional funds into our Collateral Account.

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 covenant requirements of our Amended Credit Facility and additional deposits made into the Collateral Account. Please read Part I, Item 1, Note 5, “Long-Term Debt” of this report for a description of our Amended Credit Facility.

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Organic expansion projects and acquisitions are key elements of our business strategy. We intend to finance our growth capital primarily through the issuance of debt and equity. The timing, size or success of any acquisition or expansion effort and the associated potential capital commitments are unpredictable. To consummate acquisitions or capital projects, we may require access to additional capital. Our access to capital over the longer term will depend on our future operating performance, financial condition and credit rating and, more broadly, on the availability of equity and debt financing, which will be affected by prevailing conditions in our industry, the economy and the financial markets and other financial and business factors, many of which are beyond our control.

Cash Flows

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



	Nine Months Ended September 30,
		2013			2012
Net cash provided by operating activities		$	3,462		$	15,062
Net cash used in investing activities		$	(88,820	)	$	(112,450	)
Net cash provided by financing activities		$	78,654		$	99,869

Operating cash flows — Net cash provided by operating activities was $3.5 million for the nine months ended September 30, 2013, compared to $15.1 million for the nine months ended September 30, 2012. The decrease in cash from operating activities was the result of lower net income, net of non-cash charges, of $10.9 million. In addition, the overall decrease in operating cash flows of $11.6 million included increases to operating expenses period over period from increased operational activities, additional administrative infrastructure and the annual payment of property taxes of $4.0 million during the first quarter of 2013.

Investing cash flows — Net cash used in investing activities for the nine months ended September 30, 2013 was $88.8 million, compared to $112.5 million for the nine months ended September 30, 2012. The decrease of $23.6 million primarily relates to the decrease in capital spending period over period related primarily to the completion of the Bee Line and Bonnie View fractionation facility in February 2013. During the nine months ended September 30, 2013, we spent $84.1 million in growth capital and $2.1 million in maintenance capital. In addition to capital spending, we spent a net amount of $2.7 million at our Gregory facility related to a fire that occurred in January 2013 to return the plant to service.

Financing cash flows — Net cash provided by financing activities for the nine months ended September 30, 2013 was $78.7 million, compared to $99.9 million for the nine months ended September 30, 2012. The increase was due to increased net borrowings of $22.6 million period over period offset by distributions paid of $25.9 million. Also, the issuance of our Series A Preferred Units increased cash from financing activities by $38.8 million for the nine months ended September 30, 2013. For the nine months ended September 30, 2012, our predecessor received net proceeds of $42.8 million from the issuance of its Series B redeemable preferred units offset by the repurchase and retirement of its common units and financing costs paid. Also, for the nine months ended September 30, 2012, our predecessor received proceeds of $30.0 million from the issuance of its Series C redeemable preferred units.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Recent Accounting Pronouncements

For information on new accounting pronouncements, see Part I, Item 1, Note 2, “Basis of Presentation and Summary of Significant Accounting Policies” 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 accounting principles generally accepted in the United States 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.

There have been no material changes to our quantitative and qualitative disclosures about market risk described in Item 7A to our 2012 Annual Report on Form 10-K.

Item 4. Controls and Procedures.

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

Internal control over financial reporting. There have been no changes in internal controls over financial reporting (as defined in Rule 13a—15(f) or Rule 15d—15(f) of the Exchange Act) during the third fiscal quarter of 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

A description of our material legal proceedings is included in Part I, Item 1, Note 9, “Commitments and Contingencies – Legal Matters” 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, results of operations, and financial condition and ability to make distributions.

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

The disclosures under the caption “Private Placement of our Series A Preferred Units” included in Part II, Item 9B, “Other Information” in our 2012 Annual Report on Form 10-K and Part I, Item 1, Note 11, “Series A Preferred Units,” of this report are incorporated herein by reference. The Series A Preferred Units were issued and sold pursuant to the Purchase Agreement in a transaction exempt from registration under section 4(2) of the Securities Act of 1933, as amended, and the rules and regulations promulgated thereunder.

Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

On November 12, 2013, we amended our employment offer letter with Donna A. Henderson, our Chief Accounting Officer, to increase the severance benefits for which she is eligible from one times her base salary in effect at the time of any termination of her employment to one and one-half times such base salary, if our General Partner terminates Ms. Henderson’s employment without “Cause” within one year following a “Change of Control” (as such terms are defined in our 2012 Long-Term Incentive Plan). All other terms of Ms. Henderson’s employment offer letter remain in effect.

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Item 6. Exhibits.

The information set forth in the Index to Exhibits accompanying this report is incorporated into this Item 6 by reference.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



	SOUTHCROSS ENERGY PARTNERS, L.P.

	By:	Southcross Energy Partners GP, LLC, its general partner


Date: November 13, 2013	By:	/s/ J. Michael Anderson
		J. Michael Anderson
		Senior Vice President and Chief Financial Officer
		Principal Financial Officer

Date: November 13, 2013	By:	/s/ Donna A. Henderson
		Donna A. Henderson
		Vice President and Chief Accounting Officer
		Principal Accounting Officer

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		INDEX TO 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).
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.