Southcross Energy Partners 10Q 2016 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended September 30, 2016



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

For the transition period from to

Commission File Number: 001-35719

Southcross Energy Partners, L.P.

(Exact name of registrant as specified in its charter)



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



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

(214) 979-3700

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

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

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



Large accelerated filer o		Accelerated filer x

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

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

As of November 3, 2016, the registrant has 37,015,604 common units outstanding, 12,213,713 subordinated units outstanding and 16,811,649 Class B Convertible Units outstanding. Our common units trade on the NYSE under the symbol “SXE.”

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Commonly Used Terms

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

/d: Per day

/gal: Per gallon

Bbls: Barrels

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

MMBtu: One million British thermal units

Mcf: One thousand cubic feet

MMcf: One million cubic feet

NGLs: Natural gas liquids, which consist primarily of ethane, propane, isobutane, normal butane, natural gasoline and stabilized condensate

Residue gas: Pipeline quality natural gas remaining after natural gas is processed and NGLs and other matters are removed

Rich gas: Natural gas that is high in NGL content

Throughput: The volume of natural gas and NGLs transported or passing through a pipeline, plant, terminal or other facility

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

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FORM 10-Q

TABLE OF CONTENTS

Southcross Energy Partners, L.P.



PART I — FINANCIAL INFORMATION		4

ITEM 1.	Financial Statements (Unaudited)	4

	Condensed Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015	4

	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2016 and 2015	5

	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2016 and 2015	6

	Condensed Consolidated Statements of Changes in Partners’ Capital for the Nine Months Ended September 30, 2016 and 2015	7

	Notes to Condensed Consolidated Financial Statements (Unaudited)	9

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	40

ITEM 4.	Controls and Procedures	40

PART II — OTHER INFORMATION		41

ITEM 1.	Legal Proceedings	41

ITEM 1A.	Risk Factors	41

ITEM 2.	Unregistered Sales of Equity Securities	41

ITEM 5.	Other Information	41

ITEM 6.	Exhibits	41

SIGNATURES		43

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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, 2016		December 31, 2015
ASSETS
Current assets:
Cash and cash equivalents	$	4,115	$	11,348
Trade accounts receivable	37,120		39,585
Accounts receivable - affiliates	5,283		49,734
Prepaid expenses	3,995		3,915
Other current assets	1,526		1,256
Total current assets	52,039		105,838

Property, plant and equipment, net	1,008,342		1,066,001
Investments in joint ventures	134,457		140,526
Other assets	2,222		6,595
Total assets	$	1,197,060	$	1,318,960

LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	48,074	$	66,458
Accounts payable - affiliates	—		7,871
Current portion of long-term debt	4,500		4,500
Other current liabilities	7,466		10,406
Total current liabilities	60,040		89,235

Long-term debt	544,409		604,518
Other non-current liabilities	8,665		3,871
Total liabilities	613,114		697,624

Commitments and contingencies (Note 7)

Partners' capital:
Common units (36,987,913 and 28,420,619 units outstanding as of September 30, 2016 and December 31, 2015, respectively)	257,977		271,236
Class B Convertible units (16,811,649 and 15,958,990 units issued and outstanding as of September 30, 2016 and December 31, 2015)	288,080		300,596
Subordinated units (12,213,713 units issued and outstanding as of September 30, 2016 and December 31, 2015)	26,689		37,920
General partner interest	11,200		11,584
Total partners' capital	583,946		621,336
Total liabilities and partners' capital	$	1,197,060	$	1,318,960

See accompanying notes.

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SOUTHCROSS ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except for per unit data)

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Revenues:
Revenues	$	123,043		$	147,114		$	316,673		$	471,735
Revenues - affiliates	21,619			32,455			72,418			60,993
Total revenues	144,662			179,569			389,091			532,728

Expenses:
Cost of natural gas and liquids sold	108,572			133,401			273,638			399,111
Operations and maintenance	17,781			19,139			54,173			61,528
Depreciation and amortization	31,449			17,853			68,898			52,456
General and administrative	6,831			6,803			22,879			23,612
Impairment of assets	476			—			476			193
Loss (gain) on sale of assets, net	(179		)	(33		)	(12,755		)	146
Total expenses	164,930			177,163			407,309			537,046

Income (loss) from operations	(20,268		)	2,406			(18,218		)	(4,318		)
Other expense:
Equity in losses of joint venture investments	(3,694		)	(3,567		)	(10,656		)	(10,722		)
Interest expense	(8,598		)	(8,688		)	(26,601		)	(24,087		)
Total other expense	(12,292		)	(12,255		)	(37,257		)	(34,809		)
Loss before income tax benefit	(32,560		)	(9,849		)	(55,475		)	(39,127		)
Income tax benefit	—			190			2			113
Net loss	$	(32,560	)	$	(9,659	)	$	(55,473	)	$	(39,014	)
General partner unit in-kind distribution	(12		)	(28		)	(38		)	(165		)
Net loss attributable to Holdings	—			—			—			(4,258		)
Net loss attributable to partners	$	(32,572	)	$	(9,687	)	$	(55,511	)	$	(34,921	)

Earnings per unit and distributions declared
Net loss allocated to limited partner common units	$	(17,915	)	$	(4,799	)	$	(29,235	)	$	(16,711	)
Weighted average number of limited partner common units outstanding	36,947			28,372			33,119			26,234
Basic and diluted loss per common unit	$	(0.48	)	$	(0.17	)	$	(0.88	)	$	(0.64	)

Net loss allocated to limited partner subordinated units	$	(5,920	)	$	(2,065	)	$	(10,777	)	$	(7,777	)
Weighted average number of limited partner subordinated units outstanding	12,214			12,214			12,214			12,214
Basic and diluted loss per subordinated unit	$	(0.48	)	$	(0.17	)	$	(0.88	)	$	(0.64	)
Distributions declared and paid per common unit	$	—		$	0.40		$	—		$	1.20

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,
	2016			2015
Cash flows from operating activities:
Net loss	$	(55,473	)	$	(39,014	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization	68,898			52,456
Unit-based compensation	2,635			3,513
Amortization of deferred financing costs and PIK interest	2,796			2,615
Loss (gain) on sale of assets, net	(12,755		)	146
Unrealized loss (gain) on financial instruments	(116		)	289
Equity in losses of joint venture investments	10,656			10,722
Distribution from joint venture investment	740			500
Impairment of assets	476			193
Other, net	(247		)	(69		)
Changes in operating assets and liabilities:
Trade accounts receivable, including affiliates	46,444			5,613
Prepaid expenses and other current assets	(656		)	(1,516		)
Other non-current assets	(63		)	77
Accounts payable and accrued liabilities	(24,685		)	(14,180		)
Other liabilities, including affiliates	2,553			3,163
Net cash provided by operating activities	41,203			24,508
Cash flows from investing activities:
Capital expenditures	(17,329		)	(93,946		)
Insurance proceeds (expenditures) from property damage claims	125			(2,482		)
Net proceeds from sales of assets	20,734			4,693
Consideration paid for Holdings' drop-down acquisition	—			(15,000		)
Investment contributions to joint venture investments	(5,327		)	(2,474		)
Net cash used in investing activities	(1,797		)	(109,209		)
Cash flows from financing activities:
Borrowings under our credit facility	3,110			136,000
Repayments under our credit facility	(62,250		)	(31,000		)
Repayments under our term loan agreement	(3,375		)	(3,375		)
Payments on capital lease obligations	(314		)	(406		)
Financing costs	(130		)	(685		)
Tax withholdings on unit-based compensation vested units	(122		)	(420		)
Payments of distributions and distribution equivalent rights	—			(35,088		)
Expenses paid by Holdings on behalf of Valley Wells' assets	—			17,858
Borrowing of senior unsecured PIK notes	14,000			—
Repayment of senior unsecured PIK notes and PIK interest	(14,260		)	—
Valley Wells operating expense cap adjustment	4,053			518
Contributions from general partner	—			1,301
Common unit issuances to Holdings related to equity cures	12,416			—
Interest on receivable due from Holdings	233			—
Net cash provided by (used in) financing activities	(46,639		)	84,703

Net increase (decrease) in cash and cash equivalents	(7,233		)	2
Cash and cash equivalents — Beginning of period	11,348			1,649
Cash and cash equivalents — End of period	$	4,115		$	1,651

See accompanying notes.

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SOUTHCROSS ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(In thousands)

(Unaudited)



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

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	Partners' Capital
	Limited Partners
	Common			Class B Convertible			Subordinated			General Partner			Southcross Holdings' equity in contributed subsidiaries			Total
BALANCE - December 31, 2014	$	259,735		$	298,833		$	48,831		$	12,385		$	77,320		$	697,104
Net loss	(16,583		)	(9,722		)	(7,755		)	(696		)	(4,258		)	(39,014		)
Contributions from general partner	—			—			—			1,301			—			1,301
Class B Convertible unit in-kind distribution	(5,340		)	8,059			(2,557		)	(162		)	—			—
Unit-based compensation on long-term incentive plan	3,384			—			—			—			—			3,384
Cash distributions and distribution equivalent rights paid	(30,366		)	—			(3,432		)	(1,290		)	—			(35,088		)
Accrued distribution equivalent rights on long-term incentive plan	(703		)	—			—			—			—			(703		)
Tax withholdings on unit-based compensation vested units	(419		)	—			—			—			—			(419		)
General partner unit in-kind distribution	(112		)	—			(53		)	165			—			—
Valley Wells' operating expense cap adjustment	1,023			—			—			—			—			1,023
Purchase of assets in Holdings drop-down acquisition	62,640			—			—			—			(77,640		)	(15,000		)
Contribution of NGL pipelines in Holdings drop-down acquisition	—			—			—			—			15,000			15,000
Net assets contributed in Holdings drop-down acquisition in excess of consideration paid	14,806			7,929			6,387			594			(29,716		)	—
Expenses paid by Holdings on behalf of Valley Wells' assets	—			—			—			—			17,858			17,858
Net liabilities assumed by Holdings in Holdings drop-down acquisition	—			—			—			—			1,436			1,436
BALANCE - September 30, 2015	$	288,065		$	305,099		$	41,421		$	12,297		$	—		$	646,882

See accompanying notes.

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SOUTHCROSS ENERGY PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. ORGANIZATION AND DESCRIPTION OF BUSINESS

Organization

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

Southcross Holdings LP, a Delaware limited partnership (“Holdings”), indirectly owns 100% of Southcross Energy Partners GP, LLC, a Delaware limited liability company, our General Partner (“General Partner”) (and therefore controls us), all of our subordinated and Class B convertible units and 40.6% of our common units. Our General Partner owns an approximate 2.0% interest in us and all of our incentive distribution rights.

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

Holdings Chapter 11 Reorganization

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

Liquidity Consideration

Our future cash flow will be materially adversely affected if the prolonged deterioration of natural gas, NGL and crude oil prices continues or if the reduction in drilling for oil or natural gas continues in the geographic areas in which we operate, primarily the Eagle Ford Shale region. The majority of our revenue is derived from fixed-fee and fixed-spread contracts, which have limited direct exposure to commodity price levels since we are paid based on the volumes of natural gas that we gather, process, treat, compress and transport and the volumes of NGLs we fractionate and transport, rather than being paid based on the value of the underlying natural gas or NGLs. In addition, a portion of our contract portfolio contains minimum volume commitment arrangements. The majority of our volumes are dependent upon the level of producer drilling activity. With the current price environment and reduction in drilling activity, we have begun to implement cost saving initiatives to improve future cash flows.

After considering these uncertainties, our forecast indicates future shortfalls in the amount of consolidated EBITDA (as defined in the Third Amended and Restated Revolving Credit Agreement with Wells Fargo, N.A., UBS Securities LLC and Barclays Bank PLC and a syndicate of lenders (the “Third A&R Revolving Credit Agreement”), as amended in May 2015) necessary to remain in compliance with the consolidated total leverage ratio of our Financial Covenants (as defined in Note 6) in our Credit Facility (as defined in Note 6) for the remainder of 2016 and continuing into 2017. As discussed in further detail in Note 6, we have the right to cure such a Financial Covenant Default (as defined in Note 6) by either our Sponsors or Holdings purchasing equity interests in or making capital contributions (an equity cure) resulting in, among other things, proceeds that, if added to consolidated EBITDA, would result in us satisfying the Financial Covenants. Once such an equity cure is made, it is included in our consolidated EBITDA calculation in any rolling twelve month period that includes the quarter

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that was cured. Should there be an event of default under the Credit Facility, and such default is not cured, we also would experience a cross default under our Term Loan Agreement (defined in Note 6) and all of our debt would become due and payable to our lenders.

On March 17, 2016, we entered into an equity cure contribution agreement (the “Equity Cure Agreement”) with Holdings whereby we have the right to cure any default with respect to our Financial Covenants by having Holdings purchase equity interests in or make capital contributions to us, in an aggregate amount of up to $50 million. The fair value of the Equity Cure Agreement was not material at inception. In connection with Holdings' Chapter 11 reorganization, and pursuant to the terms of the Equity Cure Agreement, Holdings has committed to contribute up to $50 million to us (the “Contribution Amount”) to comply with applicable Financial Covenants through the quarter ended December 31, 2016. In exchange for the Contribution Amount, we will issue Holdings a number of our common units representing limited partner interests equal to, subject to certain exceptions, (i) the applicable Contribution Amount divided by (ii) a common unit reference price (“Reference Price”) equal to the volume weighted daily average price of the common units on the New York Stock Exchange (“VWAP”) calculated for a period of 15 trading days ending two trading days prior to the contribution by Holdings. Notwithstanding the VWAP calculation, the Reference Price will be no less than $0.89 per common unit and no greater than $1.48 per common unit.

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

The Partnership is currently in active and constructive discussions with its lenders regarding a potential amendment to the Financial Covenants and terms contained in our Third A&R Revolving Credit Agreement. An amendment to the Financial Covenants requires the approval of lenders representing over 50% of the total revolving credit exposure. Should such an amendment not occur, we expect that additional equity cures will be required to maintain compliance with our Financial Covenants for the quarter ended December 31, 2016. If the Sponsors, either directly or through Holdings, elect not to fund the necessary additional equity cures to maintain compliance with our Financial Covenants, then we may need to seek other alternatives in order to continue as a going concern.

On January 7, 2016, in response to our need for additional liquidity, we issued at par senior unsecured PIK notes in the aggregate principal amount of $14.0 million (the "PIK Notes") to affiliates of EIG and Tailwater, with interest at a rate of 7% due January 7, 2017. Contemporaneous with the resolution of Holdings’ bankruptcy proceedings in April 2016, the PIK Notes and the related PIK interest of $0.3 million were repaid in full.

Distribution Suspension

The board of directors of our General Partner voted not to pay a quarterly distribution with respect to the fourth quarter of 2015 and the first, second and third quarters of 2016 and instead, based on current conditions, to reserve any excess cash for the operation of our business. The board of directors of our General Partner and our management believe this suspension to be in the best interest of our unitholders and will continue to evaluate the Partnership's ability to reinstate the distribution in future periods. See Note 3.

Segments

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

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Basis of Presentation

We prepared this report under the rules and regulations of the Securities and Exchange Commission (the “SEC”) and in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial statements. Accordingly, these condensed consolidated financial statements do not include all of the disclosures required by GAAP and should be read in conjunction with our 2015 Annual Report on Form 10-K (“2015 Annual Report on Form 10-K”). The condensed consolidated financial statements as of September 30, 2016 and December 31, 2015, and for the three and nine months ended September 30, 2016 and 2015, are unaudited and have been prepared on the same basis as the audited financial statements included in our 2015 Annual Report on Form 10-K. Adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the results of operations and financial position have been included herein. All intercompany accounts and transactions have been eliminated in the preparation of the accompanying condensed consolidated financial statements.

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

The accompanying unaudited condensed consolidated financial statements were prepared in conformity with GAAP, which requires management to make various estimates and assumptions that may affect the amounts of assets and liabilities, disclosures of contingent assets and liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the period. Actual results may differ from those estimates. Information for interim periods may not be indicative of our operating results for the entire year.

The disclosures included in this report provide an update to our 2015 Annual Report on Form 10-K.

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

Significant Accounting Policies

During the third quarter of 2016, there were no material changes to our significant accounting policies described in Note 1 of our 2015 Annual Report on Form 10-K.

Recent Accounting Pronouncements

Accounting standard-setting organizations frequently issue new or revised accounting pronouncements. We review and evaluate new pronouncements and existing pronouncements below to determine their impact, if any, on our condensed consolidated financial statements. We are evaluating the impact of each pronouncement on our condensed consolidated financial statements.

In February 2015, the Financial Accounting Standards Board (“FASB”) issued a pronouncement that amended the current consolidation guidance with regard to variable interest entities and voting interest entities. The standard became effective in 2016 and amends the guidance and framework for determining whether a partial-interest owner in a subsidiary should consolidate and potentially revise their disclosures about certain money market funds that are not within the scope of the variable interest entity guidance and the required transition disclosures in the fiscal period in which a change in accounting principle is made. We adopted this standard, which did not have a material impact to us, in 2016.

In February 2016, the FASB issued a pronouncement amending disclosure and presentation requirements for lessees and lessors to reflect more accurately the recognition of assets and liabilities that arise from leases. The pronouncement states that a lessee should recognize a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term on the face of the balance sheet. When measuring assets and liabilities arising from a lease, a lessee (and a lessor) should include payments to be made in optional periods only if the lessee is reasonably certain to exercise an option to extend the lease or not to exercise an option to terminate the lease. Similarly, optional payments to purchase the underlying asset should be included in the measurement of lease assets and lease liabilities only if the lessee is reasonably certain to exercise that purchase option. In addition, also consistent with the previous leases guidance, a lessee (and a lessor)

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should exclude most variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. This standard will become effective beginning in 2019.

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

In March 2016, the FASB issued a pronouncement amending the requirement to adopt retroactively the equity method of accounting. The pronouncement eliminates the requirement that when an investment qualifies for use of the equity method as a result of an increase in the level of ownership interest or degree of influence, an investor must adjust the investment, results of operations, and retained earnings retroactively on a step-by-step basis as if the equity method had been in effect during all previous periods that the investment had been held. The new guidance requires that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor’s previously held interest and adopt the equity method of accounting as of the date the investment becomes qualified for equity method accounting. Therefore, upon qualifying for the equity method of accounting, no retroactive adjustment of the investment is required. In addition, the pronouncement requires that an entity that has an available-for sale equity security that becomes qualified for the equity method of accounting recognize through earnings the unrealized holding gain or loss in accumulated other comprehensive income at the date the investment becomes qualified for use of the equity method. This standard will become effective beginning in 2017.

In 2014, a comprehensive new revenue recognition standard that will supersede substantially all existing revenue recognition guidance under GAAP was issued. The standard's core principle is that a company will recognize revenue when it transfers promised goods or services to customers and in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In April 2016, the FASB issued an accounting pronouncement which updates the identifying performance obligations and licensing implementation guidance. The standard will become effective beginning in 2018.

In May 2016, the FASB issued a pronouncement for the new revenue recognition guidance on assessing collectability, presentation of sales taxes, non-cash consideration, completed contracts and contract modifications. The pronouncement is intended to reduce the potential for diversity in practice at initial application and cost and complexity on an ongoing basis. The standard will become effective beginning in 2018.

In August 2016, the FASB issued a pronouncement amending the presentation of how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The standard will become effective at the beginning of 2018.

In 2014, a new going concern standard was issued that will update existing going concern guidance under GAAP. The standard’s new guidance relates to defining management’s responsibility to evaluate whether there is substantial doubt about an organization’s ability to continue as a going concern. Related disclosure in the notes to the consolidated financial statements will be required surrounding whether it is probable that the entity will not be able to meet its obligations as they become due within one year after the date that financial statements are issued. This standard will become effective as of December 31, 2016.

2. ACQUISITIONS

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

The 2015 Holdings Acquisition was deemed a transaction between entities under common control and, as such, was accounted for on an “as if pooled” basis for all periods which common control existed (which began on August 4, 2014). The Partnership’s financial results retrospectively include the financial results of the Valley Wells System and Compression Assets for all periods ending after August 4, 2014, the date of the Holdings Transaction, and before May 7, 2015. The acquired NGL pipelines were accounted for as an asset acquisition and were included in the historical financial statements beginning on May 7, 2015. As a carve-out transaction, the 2015 Holdings Acquisition had no cash accounts. As such, accounts receivable and accounts payable, along with certain other assets and liabilities that would be settled in cash, were the rights and obligations of

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Holdings as of December 31, 2014. Given their nature and the fact that carve-out financial statements are meant to represent an entity’s operations as if it had existed as of the time common control occurred, we have presented these amounts as third-party receivables and payables.

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



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

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

Supplemental Disclosures - As If Pooled Basis. As noted above, the 2015 Holdings Acquisition was between commonly controlled entities which required that we account for the acquisitions in a manner similar to a pooling of interests. As a result, the historical financial statements of the Partnership and the Valley Wells System and Compression Assets have been combined to reflect the historical operations, financial position and cash flows from the date common control began on August 4, 2014. Revenues and net income for the previously separate entities and the combined amounts for the nine months ended September 30, 2015, are as follows (in thousands):



	Nine Months Ended September 30, 2015
Partnership revenues	$	525,679
Valley Wells System and Compression Assets revenue	7,049
Combined revenues	$	532,728

Partnership net loss	$	(34,756	)
Valley Wells System and Compression Assets net loss	(4,258		)
Combined net loss	$	(39,014	)

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3. NET LOSS PER LIMITED PARTNER UNIT AND DISTRIBUTIONS

Net Loss Per Limited Partner Unit

The following is a reconciliation of net loss attributable to limited partners and the limited partner units used in the basic and diluted earnings per unit calculations for the three and nine months ended September 30, 2016 and 2015 (in thousands, except unit and per unit data):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Net loss	$	(32,560	)	$	(9,659	)	$	(55,473	)	$	(39,014	)
General partner unit in-kind distribution	(12		)	(28		)	(38		)	(165		)
Net loss attributable to Holdings	—			—			—			(4,258		)
Net loss attributable to partners	$	(32,572	)	$	(9,687	)	$	(55,511	)	$	(34,921	)

General partner's interest (1)	$	(655	)	$	(201	)	$	(1,119	)	$	(711	)
Class B Convertible limited partner interest (1)	(8,082		)	(2,622		)	(14,380		)	(9,722		)
Limited partners' interest (1)
Common	$	(17,915	)	$	(4,799	)	$	(29,235	)	$	(16,711	)
Subordinated	(5,920		)	(2,065		)	(10,777		)	(7,777		)

(1) General Partner's and limited partners’ interests are calculated based on the allocation of net losses for the period, net of the General Partner unit in-kind distributions. The Class B convertible unit (“Class B Convertible Units”) interest is calculated based on the allocation of only net losses for the period.



	Three Months Ended September 30,						Nine Months Ended September 30,
Common Units	2016			2015			2016			2015
Interest in net loss	$	(17,915	)	$	(4,799	)	$	(29,235	)	$	(16,711	)
Effect of dilutive units - numerator (1)	—			—			—			—
Dilutive interest in net loss	$	(17,915	)	$	(4,799	)	$	(29,235	)	$	(16,711	)

Weighted-average units - basic	36,947,132			28,371,903			33,118,605			26,233,614
Effect of dilutive units - denominator (1)	—			—			—			—
Weighted-average units - dilutive	36,947,132			28,371,903			33,118,605			26,233,614

Basic and diluted net loss per common unit	$	(0.48	)	$	(0.17	)	$	(0.88	)	$	(0.64	)

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	Three Months Ended September 30,						Nine Months Ended September 30,
Subordinated Units	2016			2015			2016			2015
Interest in net loss	$	(5,920	)	$	(2,065	)	$	(10,777	)	$	(7,777	)
Effect of dilutive units - numerator (1)	—			—			—			—
Dilutive interest in net loss	$	(5,920	)	$	(2,065	)	$	(10,777	)	$	(7,777	)

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

Basic and diluted net loss per subordinated unit	$	(0.48	)	$	(0.17	)	$	(0.88	)	$	(0.64	)

(1) Because we had a net loss for all periods for common units and the subordinated units, the effect of the dilutive units would be anti-dilutive to the per unit calculation. Therefore, the weighted average units outstanding are the same for basic and dilutive net loss per unit for those periods. The weighted average units that were not included in the computation of diluted per unit amounts was 55,202 and 17,453 for the three and nine months ended September 30, 2016, respectively.

Our calculation of the number of weighted-average units outstanding includes the common units that have been awarded to our directors that are deferred under our Non-Employee Director Deferred Compensation Plan.

Distributions

Our agreement of limited partnership (as amended and restated, the “Partnership Agreement”), requires that within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date, as determined by our General Partner. There is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Beginning with the third quarter of 2014, until such time that we have a distributable cash flow divided by cash distributions ratio (“Distributable Cash Flow Ratio”) of at least 1.0, Holdings, the indirect holder of all of our subordinated units, waived the right to receive distributions on any subordinated units that would cause the Distributable Cash Flow Ratio to be less than 1.0. In addition, the Credit Agreement Amendment (as defined in Note 6) imposed additional restrictions on our ability to declare and pay quarterly cash distributions with respect to our subordinated units. See Note 6.

Cash Distributions

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

Paid In-Kind Distributions

Class B Convertible Units. As of September 30, 2016, the Class B Convertible Units consisted of 16,811,649 of such units including the additional Class B Convertible Units issued in-kind as a distribution (“Class B PIK Units”). The Class B Convertible Units are not participating securities for purposes of the earnings per unit calculation. Commencing with the quarter ended September 30, 2014 and until converted, as long as certain requirements are met, the holders of the Class B Convertible Units will receive quarterly distributions in an amount equal to $0.3257 per unit. These distributions will be paid quarterly in Class B PIK Units within 45 days after the end of each quarter. Our General Partner was entitled, and has exercised its right, to retain its 2.0% general partner interest in us in connection with the original issuance of the Class B Convertible Units. In connection with future distributions of Class B PIK Units, the General Partner is entitled to a corresponding distribution to maintain its 2.0% general partner interest in us. The Class B Convertible Units have the same rights, preferences and privileges, and are subject to the same duties and obligations, as our common units, with certain exceptions. See Note 8.

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The following table presents the PIK distributions issued on the Class B Convertible Units during 2016 (in thousands, except per unit and in-kind distribution units):



Payment Date	Attributable to the Quarter Ended	Per Unit Distribution		In-Kind Class B Convertible Unit Distributions to Class B Convertible Holders	In-Kind Class B Convertible Distributions Value⁽¹⁾		In-Kind Unit Distribution to General Partner	In-Kind General Partner Distribution Value⁽¹⁾
2016
November 14, 2016	September 30, 2016	$	0.3257	294,226	$	433	6,004	$	9
August 10, 2016	June 30, 2016	0.3257		289,165	581		5,901	12
May 9, 2016	(2)	0.3257		563,494	1,293		11,499	26

(1) The fair value was calculated as required, based on the common unit price at the quarter end date for the period attributable to the distribution, multiplied by the number of units distributed.

(2) We suspended distributions to holders of our Class B Convertible Units for the quarters ended December 31, 2015 and March 31, 2016. However, under the terms of our Partnership agreement, such paid in-kind (“PIK”) distributions continued to accumulate. On May 9, 2016, we issued the accumulated Class B Convertible Units to Holdings and general partner units to our General Partner related to the quarters ended December 31, 2015 and March 31, 2016.

4. FINANCIAL INSTRUMENTS

Fair Value Measurements

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


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


•	Level 2—Represents quoted market prices for similar assets or liabilities in active markets, quoted market prices in markets that are not active or other inputs that are observable or can be corroborated by observable market data. This category primarily includes variable rate debt, over-the-counter swap contracts based upon natural gas price indices and interest rate derivative transactions.


•	Level 3—Represents derivative instruments whose fair value is estimated based on internally developed models and methodologies utilizing significant inputs that are generally less readily observable from market sources. We do not have financial assets and liabilities classified as Level 3.

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

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable represent fair values based on the short-term nature of these instruments. The fair value of the debt funded through our credit facilities approximates its carrying amount due primarily to the variable nature of the interest rate of the instrument and is considered a Level 2 fair value measurement.

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Derivative Financial Instruments

Interest Rate Derivative Transactions

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



						Estimated Fair Value
Notional Amount		Fixed Rate		Effective Date	Maturity Date	September 30, 2016
$	100,000	1.195	%	June 30, 2015	January 1, 2017	$	(43	)

Effectively, we enter into interest rate cap contracts to limit our London Interbank Offered Rate (“LIBOR”) based interest rate risk on the portion of debt hedged at the contracted cap rate. Our interest rate cap position was as follows (in thousands):



						Estimated Fair Value
Notional Amount		Cap Rate		Effective Date	Maturity Date	September 30, 2016
$	20,000	1.500	%	December 31, 2014	December 31, 2016	$	—
80,000		3.000	%	June 30, 2015	June 30, 2017	—
50,000		3.000	%	December 31, 2015	December 31, 2017	—
50,000		3.000	%	June 30, 2016	June 30, 2018	1
						$	1

These interest rate derivatives are not designated as cash flow hedging instruments for accounting purposes and as a result, changes in the fair value are recognized in interest expense immediately.

The fair value of our interest rate derivative transactions is determined based on a discounted cash flow method using contractual terms of the transactions. The floating coupon rate is based on observable rates consistent with the frequency of the interest cash flows. We have elected to present our interest rate derivatives net in the balance sheets. There was no effect of offsetting in the balance sheets as of September 30, 2016 or December 31, 2015.

The fair values of our interest rate derivative transactions were as follows (in thousands):



	Significant Other Observable Inputs (Level 2)
	Fair Value Measurement as of
	September 30, 2016			December 31, 2015
Current interest rate derivative assets	$	—		$	6
Non-current interest rate derivative assets	—			4
Current interest rate derivative (liabilities)	(43		)	(169		)
Total interest rate derivatives	$	(43	)	$	(159	)

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



	Three Months Ended September 30,					Nine Months Ended September 30,
	2016			2015		2016			2015
Unrealized loss (gain) on interest rate derivatives	$	(61	)	$	53	$	(116	)	$	163
Realized loss on interest rate derivatives	50			100		248			357

Commodity Swaps

In our normal course of business, periodically we enter into month-ahead swap contracts to hedge our exposure to certain intra-month natural gas index pricing risk. We had no outstanding month-ahead swap contracts as of September 30, 2016 and December 31, 2015. We define these contracts as Level 2 because the index price associated with such contracts is observable and tied to a similarly quoted first-of-the-month natural gas index price.

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



	Three Months Ended September 30,					Nine Months Ended September 30,
	2016		2015			2016		2015
Realized gain on commodity swap derivatives	$	—	$	11		$	—	$	147
Unrealized loss on commodity swap derivatives	—		(15		)	—		(126		)

5. LONG-LIVED ASSETS

Property, Plant and Equipment

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



	Estimated Useful Life (yrs)	September 30, 2016			December 31, 2015
Pipelines	15-30	$	552,810		$	542,790
Gas processing, treating and other plants	15	558,317			547,253
Compressors	7-15	76,816			72,750
Rights of way and easements	15	50,160			46,692
Furniture, fixtures and equipment	5	9,341			9,252
Capital lease vehicles	3-5	2,442			2,442
Total property, plant and equipment		1,249,886			1,221,179
Accumulated depreciation and amortization		(281,379		)	(212,991		)
Total		968,507			1,008,188

Construction in progress		16,298			32,214
Land and other		23,537			25,599
Property, plant and equipment, net		$	1,008,342		$	1,066,001

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, 2016 included $12.6 million (the earnings per unit equivalent of $0.19 for the three months ended September 30, 2016) of accelerated depreciation related to management’s plans to shut down the Conroe facility and convert the Gregory facility to a compressor station by December 31, 2016. In addition, $19.1 million is expected to be recorded during the three months ended December 31, 2016.

In May 2016, we finalized the sale of a portion of pipeline for $15.0 million, which was determined to be a sale of assets. We recorded a $13.6 million gain on sale of assets on our condensed consolidated statement of operations in connection with this sale.

Intangible Assets

Intangible assets of $1.4 million and $1.5 million as of September 30, 2016 and December 31, 2015, respectively, represent the unamortized value assigned to long-term supply and gathering contracts. These intangible assets are amortized on a straight-line basis over the 30-year expected useful lives of the contracts through 2041. Amortization expense over the next five years related to intangible assets is not significant.

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6. LONG-TERM DEBT

Our outstanding debt and related information at September 30, 2016 and December 31, 2015 are as follows (in thousands):



	September 30, 2016			December 31, 2015
Revolving credit facility due 2019	$	122,555		$	181,695
Term loans (including original issue discount of $1.5 million and $1.8 million as of September 30, 2016 and December 31, 2015, respectively) due 2021	438,335			441,464
Total long-term debt (including current portion)	560,890			623,159
Current portion of long-term debt	(4,500		)	(4,500		)
Deferred financing costs	(11,981		)	(14,141		)
Total long-term debt	$	544,409		$	604,518

Outstanding letters of credit	$	19,028		$	18,305
Remaining unused borrowings	$	58,417		$	—



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Weighted average interest rate	5.26		%	5.19		%	5.24		%	5.15		%
Average outstanding borrowings	$	571,468		$	585,283		$	601,956		$	549,342
Maximum borrowings	$	571,555		$	596,500		$	628,055		$	596,500

Senior Credit Facilities

Our long-term debt arrangements consist of (a) the Third A&R Revolving Credit Agreement (as defined in Note 1) and (b) a Term Loan Credit Agreement with Wilmington Trust, National Association, UBS Securities LLC and Barclays Bank PLC and a syndicate of lenders (the “Term Loan Agreement” and, together with the Third A&R Revolving Credit Agreement, the “Senior Credit Facilities”). Substantially all of our assets are pledged as collateral under the Senior Credit Facilities, with the security interest of the facilities ranking pari passu.

Third A&R Revolving Credit Agreement

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


(a)	the letters of credit sublimit is $75 million; and

(b)

if we fail to comply with the consolidated total leverage ratio, consolidated senior secured leverage ratio and the consolidated interest coverage ratio covenants (the “Financial Covenants”) (a “Financial Covenant Default”), we have the right (a limited number of times) to cure such Financial Covenant Default by having the Sponsors purchase equity interests in or make capital contributions to us resulting in, among other things, proceeds that, if added to consolidated EBITDA, as defined in the Third A&R Revolving Credit Agreement, would result in us satisfying the Financial Covenants.

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

The Credit Agreement Amendment, among other things:

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

(b) increased the applicable margins used in connection with the loans and the commitment fee so that the applicable margin for Eurodollar Loans (as used in the Third A&R Revolving Credit Agreement) ranges from 2.00% to 4.50%,

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the applicable margin for base rate loans ranges from 1.00% to 3.50% and the applicable rate for commitment fees ranges from 0.375% to 0.500%; and

(c) allows us an unlimited number of quarterly equity cures related to our Financial Covenant Default through the fourth quarter of 2016, and no more than two in a twelve month period thereafter for the life of the agreement. Beginning on January 1, 2017, we are limited to no more than four equity cures, with no more than two in a twelve month period. Additionally, we are unable to borrow on our Credit Facility until we have funded the required equity cure for the third quarter of 2016; however, we retain the ability to execute the required equity cure.

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

Term Loan Agreement

The Term Loan Agreement is a seven-year $450 million senior secured term loan facility maturing on August 4, 2021. Borrowings under our Term Loan Agreement bear interest at LIBOR plus 4.25% or a base rate as defined in the respective credit agreement with a LIBOR floor of 1.00%. The facility is amortized in equal quarterly installments in an aggregate annual amount equal to 1% of the original principal amount of the initial loan ($1.125 million), with the remainder due on the maturity date.

Deferred Financing Costs

Deferred financing costs are capitalized and amortized as interest expense under the effective interest method over the term of the related debt. The unamortized balance of deferred financing costs is included in long-term debt on the balance sheets. Changes in deferred financing costs are as follows (in thousands):



	2016			2015
Deferred financing costs, January 1	$	14,141		$	16,602
Capitalization of deferred financing costs	130			685
Less:
Amortization of deferred financing costs	(2,290		)	(2,362		)
Deferred financing costs, September 30	$	11,981		$	14,925

7. COMMITMENTS AND CONTINGENCIES

Legal Matters

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

Formosa. In March 2013, one of our subsidiaries, Southcross Marketing Company Ltd. (“Marketing”), filed suit against Formosa Hydrocarbons Company, Inc. (“Formosa”) for breach of contract under a gas processing and sales contract between the parties. Formosa filed a counterclaim against Marketing for breach of such contract and a related agreement between the parties. After a bench trial held in January 2015, the judge ruled that Formosa had breached certain of its obligations under the gas processing and sales contract and that Marketing had breached certain of its obligations under such contract and the related agreement. On June 27, 2016, a final judgment was entered in which Marketing was awarded damages, attorneys’ fees and interest. On July 27, 2016, Marketing filed a notice of appeal seeking to appeal certain of the rulings set forth in the final

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judgment. On September 23, 2016, Formosa filed its notice of appeal. The recording of any award will be deferred until the resolution of the appeals.

Regulatory Compliance

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

Leases

Capital Leases

We have auto leases that are classified as capital leases. The termination dates of the lease agreements vary from 2016 to 2019. We recorded amortization expense related to the capital leases of $0.1 million and $0.3 million for the three and nine months ended September 30, 2016, respectively, and $0.1 million and $0.4 million for the three and nine months ended September 30, 2015, respectively. Capital leases entered into during the three and nine months ended September 30, 2016 were $0.1 million and $0.4 million, respectively. Capital leases entered into during the three and nine months ended September 30, 2015 were less than $0.1 million and $0.4 million, respectively. The capital lease obligation amounts included on the balance sheets were as follows (in thousands):



	September 30, 2016		December 31, 2015
Other current liabilities	$	397	$	362
Other non-current liabilities	173		522
Total	$	570	$	884

Operating Leases

We maintain operating leases in the ordinary course of our business activities. These leases include those for office and other operating facilities and equipment. The termination dates of the lease agreements vary from 2016 to 2025. Expenses associated with operating leases, recorded in operations and maintenance expenses and general and administrative expenses in our statements of operations, were $1.5 million and $4.2 million for the three and nine months ended September 30, 2016, respectively, and $1.9 million and $3.7 million for the three and nine months ended September 30, 2015, respectively. A rental reimbursement included in our lease agreement associated with the office space we leased in June 2015 of $2.0 million, net of amortization, has been recorded as a deferred liability on our condensed consolidated balance sheets as of September 30, 2016. This amount will continue to be amortized against the lease payments over the length of the lease term.

Purchase Commitments

At September 30, 2016, we had commitments of $7.5 million related primarily to the purchase of equipment, treaters pipelines and compressors for our various capital expansion projects. We have other planned capital projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.

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8. PARTNERS’ CAPITAL

Ownership

Our units outstanding as of September 30, 2016 are as follows (in units):



	Partners’ Capital
		Owned by Parent
	Public	Holdings	Class B		General
	Common	Common	Convertible	Subordinated	Partner
Units outstanding as of December 31, 2015	21,804,219	6,616,400	15,958,990	12,213,713	1,154,965
Vesting of LTIP units, net	178,106	—	—	—	—
In-kind distributions and issuances to general partner to maintain 2.0% ownership	—	—	852,659	—	192,245
Common unit issuances to Holdings related to equity cures	—	8,389,188	—	—	—
Units outstanding as of September 30, 2016	21,982,325	15,005,588	16,811,649	12,213,713	1,347,210

Common Units

Our common units represent limited partner interests in us. The holders of our common units are entitled to participate in our distributions and are entitled to exercise the rights and privileges available to limited partners under our Partnership Agreement. In accordance with the requirements of the Equity Cure Agreement, Holdings was issued 8,029,729 common units on May 2, 2016 and 359,459 common units on May 13, 2016.

Class B Convertible Units

The Class B Convertible Units consist of 14,633,000 units plus any additional Class B PIK Units. The Class B Convertible Units have the same rights, preferences and privileges, and are subject to the same duties and obligations, as our common units, with certain exceptions as noted below.

Our Partnership Agreement does not allow additional Class B Convertible Units (other than Class B PIK Units) to be issued without the prior approval of our General Partner and the holders of a majority of the outstanding Class B Convertible Units. As of September 30, 2016, all of our outstanding Class B Convertible Units were indirectly owned by Holdings.

Distribution Rights: The holders of the Class B Convertible Units will receive quarterly distributions in an amount equal to $0.3257 per unit paid in Class B PIK Units (based on a unit issuance price of $18.61) within 45 days after the end of each quarter until converted and as long as certain requirements are met. Our General Partner was entitled, and has exercised its right, to retain its 2.0% general partner interest in us in connection with the original issuance of Class B Convertible Units. In connection with future distributions of Class B PIK Units, the General Partner is entitled to a corresponding distribution to maintain its 2.0% general partner interest in us.

We suspended distributions to holders of our Class B Convertible Units for the quarters ended December 31, 2015 and March 31, 2016. However, under the terms of our Partnership agreement, such paid in-kind (“PIK”) distributions continued to accumulate. On May 9, 2016, we issued the accumulated 563,494 Class B Convertible Units to Holdings and 11,499 general partner units to our General Partner related to the quarters ended December 31, 2015 and March 31, 2016. On August 10, 2016, we issued 289,165 Class B Convertible Units to Holdings and 5,901 general partner units to our General Partner related to the quarter ended June 30, 2016.

Conversion Rights: The Class B Convertible Units are convertible into common units on a one-for-one basis and, once converted, will participate in cash distributions pari passu with all other common units. The conversion of Class B Convertible Units will occur on the date we (a) make a quarterly distribution equal to or greater than $0.44 per common unit, (b) generate Class B Distributable Cash Flow (as defined in our Partnership Agreement) in an amount sufficient to pay the declared distribution on all units for the two quarters immediately preceding the date of conversion (the “measurement period”) and (c) forecast paying a distribution equal to or greater than $0.44 per unit from forecasted Class B Distributable Cash Flow on all outstanding common units for the two quarters immediately following the measurement period.

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

Subordinated Units

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

General Partner Interests

As defined by our Partnership Agreement, general partner units are not considered to be units (common or subordinated), but are representative of our general partner’s 2.0% ownership interest in us. Our General Partner has received general partner unit PIK distributions in connection with the Class B Convertible Units. In connection with other equity issuances, our General Partner has made capital contributions in exchange for additional general partner units to maintain its 2.0% ownership interest in us. In connection with the 8,029,729 common units issued to Holdings on May 2, 2016 and the 359,459 common units issued to Holdings on May 13, 2016, our General Partner made capital contributions in exchange for 171,209 general partner units to maintain its 2.0% ownership interest in us.

9. TRANSACTIONS WITH RELATED PARTIES

Affiliated Directors

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Charlesbank Capital Partners, LLC(1)	$	—	$	36	$	94	$	116
EIG	14		16		59		48
Tailwater	14		16		58		48
Total fees and expenses paid for director services to affiliated entities	$	28	$	68	$	211	$	212

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

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Southcross Energy Partners GP, LLC (our General Partner)

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Reimbursements included in general and administrative expenses	$	3,190	$	2,715	$	10,224	$	9,794
Reimbursements included in operations and maintenance expenses	5,469		4,335		16,315		14,767
Total reimbursements to our General Partner and its affiliates	$	8,659	$	7,050	$	26,539	$	24,561

Compensation expense for services incurred by us on behalf of Southcross Energy LLC was billed to Southcross Energy LLC. Compensation expense not incurred on our behalf of $0.1 million and $0.5 million for the three and nine months ended September 30, 2015, respectively, was billed to Southcross Energy LLC.

Other Transactions with Affiliates

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

In addition, on November 3, 2016, each of these executives of our General Partner received a one-time retention bonus in an amount equal to 100% of then-current annual salary for remaining employed with our General Partner through November 1, 2016. We have recorded $0.3 million and $0.9 million in general and administrative expenses for our allocable share of costs for the three and nine months ended September 30, 2016.

On January 7, 2016, in response to our need for additional liquidity, we issued at par senior unsecured PIK notes in the

aggregate principal amount of $14.0 million (the "PIK Notes") to affiliates of EIG and Tailwater, with interest at a rate of

7% due January 7, 2017. Contemporaneous with the resolution of Holdings’ bankruptcy proceedings in April 2016, the PIK Notes and the related PIK interest of $0.3 million were repaid in full.

We have a gas gathering and processing agreement (the “G&P Agreement”) and an NGL sales agreement (the “NGL Agreement”) with an affiliate of Holdings. Under the terms of these commercial agreements, we transport, process and sell rich natural gas for the affiliate of Holdings in return for agreed-upon fixed fees, and we can sell natural gas liquids that we own to Holdings at agreed-upon fixed prices. The NGL Agreement also permits us to utilize Holdings’ fractionation services at market-based rates.

We have a series of commercial agreements with affiliates of Holdings including a gas gathering and treating agreement, a compression services agreement, a repair and maintenance agreement and an NGL transportation agreement. Under the terms of these commercial agreements, we gather, treat, transport, compress and redeliver natural gas for the affiliates of Holdings in return for agreed-upon fixed fees. In addition, under the NGL transportation agreement, we transport a minimum volume of NGLs per day at a fixed rate per gallon. The operational expense associated with such agreements has been capped at $1.7 million per quarter through December 31, 2016. In the first and second quarter of 2016, we exceeded this cap by $1.0 million and $1.4 million, respectively. However, we did not exceed this cap in the third quarter of 2016.

The Partnership recorded revenues from affiliates of $21.6 million and $72.4 million for the three and nine months ended September 30, 2016, respectively, and $32.5 million and $61.0 million for the three and nine months ended September 30, 2015, respectively, in accordance with the G&P Agreement, the NGL Agreement and the series of commercial agreements.

We had accounts receivable due from affiliates of $5.3 million and $49.7 million as of September 30, 2016 and December 31, 2015, respectively, and accounts payable due to affiliates of $7.9 million as of December 31, 2015. The affiliate

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receivable and payable balances are related primarily to transactions associated with Holdings, noted above, and our joint venture investments (defined in Note 12). The receivable balance due from Holdings is current as of September 30, 2016.

10. INCENTIVE COMPENSATION

Unit Based Compensation

Long-Term Incentive Plan

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

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

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



	Units		Weighted-Average Fair Value at Grant Date
Unvested - December 31, 2015	687,920		$	15.56
Granted units	47,500		$	3.56
Forfeited units	(40,322	)	$	17.39
Units recaptured for tax withholdings	(77,371	)	$	17.19	(1	)
Vested units	(178,106	)	$	16.45	(1	)
Unvested - September 30, 2016	439,621		$	14.83

(1) The weighted-average fair value price on the date of vesting for our vested units was $1.57. The weighted-average fair value price on the date of vesting for our units recaptured for tax withholdings was $1.52.

For the nine months ended September 30, 2016, we granted awards under the LTIP with a grant date fair value of $0.2 million which we have classified as equity awards. As of September 30, 2016, we had total unamortized compensation expense of $4.4 million related to unvested awards. Compensation expense associated with awards granted on March 10, 2015 of 84,423 units was recognized over a one-year vesting period, while compensation expense for the remaining awards is expected to be recognized over the three-year vesting period from each equity award’s grant date. As of September 30, 2016, we had 5,128,267 units available for issuance under the LTIP.

Unit Based Compensation Expense

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Unit-based compensation	$	929	$	1,038	$	2,635	$	3,513

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Employee Savings Plan

We have employee savings plans under Sections 401(a) and 401(k) of the Internal Revenue Code of 1986, as amended, whereby employees of our General Partner may contribute a portion of their base compensation to the employee savings plan, subject to limits. We provide a matching contribution each payroll period equal to 100% of each employee’s contribution up to the lesser of 6% of the employee’s eligible compensation or $18,000 annually for the period. The following table summarizes information regarding contributions and the expense recognized for the matching contributions, which is included in general and administrative expense on our statements of operations (in thousands):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Matching contributions expensed for employee savings plan	$	338	$	180	$	946	$	519

11. REVENUES

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Sales of natural gas	$	76,614	$	104,050	$	192,673	$	309,355
Sales of NGLs and condensate	39,640		38,704		107,662		115,314
Transportation, gathering and processing fees	27,775		35,130		85,067		104,006
Other	633		1,685		3,689		4,053
Total revenues	$	144,662	$	179,569	$	389,091	$	532,728

12. INVESTMENTS IN JOINT VENTURES

We own equity interests in three joint ventures with Targa Pipeline Partners LP as our joint venture partner. T2 Eagle Ford Gathering Company LLC (“T2 Eagle Ford”), T2 LaSalle Gathering Company LLC (“T2 LaSalle”) and T2 EF Cogeneration Holdings LLC (“T2 Cogen”) operate pipelines and a cogeneration facility located in South Texas. We indirectly own a 50% interest in T2 Eagle Ford, a 50% interest in T2 Cogen and a 25% interest in T2 LaSalle. We pay our proportionate share of the joint ventures’ operating costs, excluding depreciation and amortization, through lease capacity payments. As a result, our share of the joint ventures’ losses is related primarily to the joint ventures’ depreciation and amortization. Our maximum exposure to loss related to these joint ventures includes our equity investment, any additional capital contributions and our share of any operating expenses incurred by the joint ventures. The joint ventures’ summarized financial data from their statements of operations for the three and nine months ended September 30, 2016 and 2015 is as follows (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Revenue
T2 Eagle Ford	$	1,393		$	1,215		$	4,437		$	3,351
T2 Cogen	557			1,218			2,556			4,067
T2 LaSalle	456			450			1,250			1,279

Net loss
T2 Eagle Ford	$	(4,878	)	$	(4,977	)	$	(14,383	)	$	(14,952	)
T2 Cogen	(1,767		)	(1,447		)	(4,727		)	(4,300		)
T2 LaSalle	(1,486		)	(1,419		)	(4,405		)	(4,384		)

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Our equity in losses of joint venture investments is comprised of the following for the three and nine months ended September 30, 2016 and 2015 (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
T2 Eagle Ford	$	(2,439	)	$	(2,489	)	$	(7,192	)	$	(7,476	)
T2 Cogen	(883		)	(723		)	(2,363		)	(2,150		)
T2 LaSalle	(372		)	(355		)	(1,101		)	(1,096		)
Equity in losses of joint venture investments	$	(3,694	)	$	(3,567	)	$	(10,656	)	$	(10,722	)

Our investments in joint ventures is comprised of the following as of September 30, 2016 and December 31, 2015 (in thousands):



	September 30, 2016		December 31, 2015
T2 Eagle Ford	$	104,056	$	105,755
T2 Cogen	13,639		16,747
T2 LaSalle	16,762		18,024
Investments in joint ventures	$	134,457	$	140,526

13. CONCENTRATION OF CREDIT RISK

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

Our top ten customers for the three and nine months ended September 30, 2016 and 2015 represent the following percentages of consolidated revenue:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Top ten customers	55.1	%	50.0	%	59.0	%	53.3	%

The percentage of total consolidated revenue for each customer that exceeded 10% of total revenues for the three and nine months ended September 30, 2016 and 2015 was as follows:



	Three Months Ended September 30,			Nine Months Ended September 30,
	2016		2015	2016	2015
TexStar Midstream(b)	10.7	%	(a)	(a)	(a)

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

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

For the nine months ended September 30, 2016 and 2015, we did not experience significant non-payment for services. As of September 30, 2016 and December 31, 2015, we had an allowance for uncollectible accounts receivable of $0.1 million.

14. SUBSEQUENT EVENTS

On November 8, 2016, we entered into the Amendment. See Note 1 for additional details.

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15. SUPPLEMENTAL INFORMATION

Supplemental Cash Flow Information (in thousands)



	Nine Months Ended September 30,
	2016		2015
Supplemental Disclosures:
Cash paid for interest, net of amounts capitalized	$	26,197	$	22,364
Cash received for tax refunds	52		58
Supplemental disclosures of non-cash investing and financing activities:
Accounts payable related to capital expenditures	4,039		8,133
Capital lease obligations	—		378
Accrued distribution equivalent rights on LTIP units	11		685
Class B Convertible unit in-kind distributions	1,874		8,059
Net assets contributed in Holdings drop-down acquisition in excess of consideration paid	—		29,716
Valley Wells' operating expense cap adjustment	—		505
Purchase of assets in Holdings drop-down acquisition	—		62,640
Net liabilities assumed by Holdings in Holdings drop-down acquisition	—		1,436
PIK interest	260		—
Common unit issuances to General Partner related to equity cures	504		—

Capitalization of Interest Cost

We capitalize interest on projects during their construction period. Once a project is placed in service, capitalized interest, as a component of the total cost of the construction, is depreciated over the estimated useful life of the asset constructed. We incurred the following interest costs (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Total interest costs	$	8,783		$	9,170		$	27,338		$	25,629
Capitalized interest included in property, plant and equipment, net	(185		)	(482		)	(737		)	(1,542		)
Interest expense	$	8,598		$	8,688		$	26,601		$	24,087

Southcross Assets Considered Leases to Third Parties

We have pipelines that transport natural gas to two power plants in Nueces County, Texas under fixed-fee contracts. The contracts have a primary term through 2029 and an option to extend the agreements by an additional term of up to ten years. These contracts are considered operating leases under the applicable accounting guidance.

Future minimum annual demand payment receipts under these agreements as of September 30, 2016 were as follows: $1.4 million for the remainder of 2016; $5.6 million in 2017; $2.2 million in 2018; $2.2 million in 2019; $2.2 million in 2020 and $13.1 million thereafter. The revenue for the demand payments is recognized on a straight-line basis over the term of the contract. The demand fee revenues under the contracts were $0.7 million and $2.0 million for the three and nine months ended September 30, 2016, respectively, and $0.7 million and $2.0 million for the three and nine months ended September 30, 2015 respectively, and have been included within transportation, gathering and processing fees within Note 11. These amounts do not include variable fees based on the actual gas volumes delivered under the contracts. Variable fees recognized in revenues within transportation, gathering and processing fees within Note 11 were $0.8 million and $2.3 million for the three and nine months ended September 30, 2016, respectively, and $0.8 million and $2.3 million for the three and nine months ended September 30, 2015, respectively. Deferred revenue associated with these agreements was $7.3 million and $5.3 million at September 30, 2016 and December 31, 2015, respectively.

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

FORWARD-LOOKING INFORMATION

Investors are cautioned that certain statements contained in this report as well as in periodic press releases and oral statements made by our management team during our presentations are “forward-looking” statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will continue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would” and “could.” In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us or our subsidiaries, are also forward-looking statements. These forward-looking statements involve external risks and uncertainties, including, but not limited to, those described under the section entitled “Risk Factors” included in our 2015 Annual Report on Form 10-K.

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


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


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


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


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


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


•	the financial condition and creditworthiness of our customers;


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


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


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


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


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


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


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


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


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


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


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


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


•	the effects of laws and governmental regulations and policies;


•	the effects of existing and future litigation;


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


•	changes in general economic conditions;


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


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

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

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

Overview

Southcross Holdings LP, a Delaware limited partnership (“Holdings”), indirectly owns 100% of Southcross Energy Partners GP, LLC, a Delaware limited liability company, our General Partner (“General Partner”) (and therefore controls us), all of our subordinated units and Class B convertible units and 40.6% of our common units. Our General Partner owns an approximate 2.0% interest in us and all of our incentive distribution rights.

Recent Developments

Holdings Chapter 11 Reorganization

Liquidity Consideration

As of September 30, 2016, we were not in compliance with the consolidated total leverage ratio of our Financial Covenants absent an equity cure of $17.0 million being received within approximately 15 days following the issuance of these financial statements.We believe that we will have the ability to fund this equity cure through an equity cure contribution agreement (the “Equity Cure Agreement”, discussed below) entered into on March 17, 2016 with Holdings whereby we have the right to cure any default with respect to our Financial Covenants by having Holdings purchase equity interests in or make capital contributions to us, in an aggregate amount of up to $50 million. We used an aggregate $12.4 million of the $50 million equity commitment from Holdings to fund equity cures as of December 31, 2015 and March 31, 2016. In accordance with the requirements above and the amounts funded for these equity cures, Holdings was issued 8,029,729 common units on May 2, 2016 for the fourth quarter 2015 equity cure ($11.9 million) that was funded in March 2016 and 359,459 common units on May 13, 2016 for the first quarter 2016 equity cure ($0.5 million) that was funded in July 2016. In addition, our forecast indicates future shortfalls in the amount of consolidated EBITDA necessary to remain in compliance with the consolidated total leverage ratio of our Financial Covenants in our Credit Facility (defined below) for the remainder of 2016. The Partnership is currently in active and constructive discussions with its lenders regarding a potential amendment to the Financial Covenants and terms

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contained in our Third A&R Revolving Credit Agreement. An amendment to the Financial Covenants requires the approval of lenders representing over 50% of the total revolving credit exposure. Should such an amendment not occur, we expect that additional equity cures will be required to maintain compliance with our Financial Covenants for the quarter ended December 31, 2016. If the Sponsors, either directly or through Holdings, elect not to fund the necessary additional equity cures to maintain compliance with our Financial Covenants, then we may need to seek other alternatives in order to continue as a going concern.

Distribution Suspension

Our Operations

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

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


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

•

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

•

Commodity-Sensitive. In exchange for our processing services, we may remit to a customer a percentage of the proceeds from our sales, or a percentage of the physical volume, of residue natural gas and/or NGLs that result from our natural gas processing, or we may purchase NGLs from customers at set fixed NGL recoveries and retain the balance of the proceeds or physical commodity for our own account. These arrangements are generally combined with fixed-fee and fixed-spread arrangements for processing services and, therefore, represent only a portion of a processing contract's value. The revenues we receive from these arrangements directly correlate with fluctuating general commodity price levels of natural gas and NGLs and the volume of NGLs recovered relative to the fixed recovery obligations.

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

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our fixed-fee and fixed-spread arrangements. For our gathering, transportation and other services agreements with Holdings (see Note 9 to our condensed consolidated financial statements), fee based revenue increases with no associated cost of natural gas and liquids sold. We enter into primarily fixed-fee and fixed-spread deals.

How We Evaluate Our Operations

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

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

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

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

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

Adjusted EBITDA is a key metric used in measuring our compliance with our financial covenants under our debt agreements and is used as a supplemental measure by our management and by external users of these financial statements, such as investors, commercial banks, research analysts and others, to assess:


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


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


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

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

Distributable cash flow is used to assess:


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


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

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Non-GAAP Financial Measures

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

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Reconciliations of Non-GAAP Financial Measures

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Net cash provided by operating activities	$	11,256		$	20,005		$	41,203		$	24,508
Add (deduct):
Depreciation and amortization	(31,449		)	(17,853		)	(68,898		)	(52,456		)
Unit-based compensation	(929		)	(1,038		)	(2,635		)	(3,513		)
Amortization of deferred financing costs and PIK interest	(892		)	(888		)	(2,796		)	(2,615		)
Gain (loss) on sale of assets, net	179			33			12,755			(146		)
Unrealized gain (loss) on financial instruments	61			(68		)	116			(289		)
Equity in losses of joint venture investments	(3,694		)	(3,567		)	(10,656		)	(10,722		)
Distribution from joint venture investment	(350		)	(500		)	(740		)	(500		)
Impairment of assets	(476		)	—			(476		)	(193		)
Other, net	63			67			247			69
Changes in operating assets and liabilities:
Trade accounts receivable, including affiliates	(2,035		)	11,338			(46,444		)	(5,613		)
Prepaid expenses and other current assets	(1,679		)	2,296			656			1,516
Other non-current assets	63			(1		)	63			(77		)
Accounts payable and accrued liabilities	(3,123		)	(17,224		)	24,685			14,180
Other liabilities, including affiliates	445			(2,259		)	(2,553		)	(3,163		)
Net loss	$	(32,560	)	$	(9,659	)	$	(55,473	)	$	(39,014	)
Add (deduct):
Depreciation and amortization	$	31,449		$	17,853		$	68,898		$	52,456
Interest expense	8,598			8,688			26,601			24,087
Income tax benefit	—			(190		)	(2		)	(113		)
Unrealized loss on commodity swap derivatives	—			(15		)	—			(126		)
Loss (gain) on sale of assets, net	(179		)	(33		)	(12,755		)	146
Revenue deferral adjustment	754			754			2,262			2,262
Unit-based compensation	929			1,038			2,635			3,513
Major litigation costs, net of recoveries	173			18			416			509
Transaction-related costs	—			613			6			1,785
Equity in losses of joint venture investments	3,694			3,567			10,656			10,722
Severance expense	—			—			16			734
Retention bonus due from Holdings	898			—			2,694			—
Valley Wells' operating expense cap adjustment	—			505			2,406			1,023
Fees related to Equity Cure Agreement	12			—			589			—
Distribution from joint venture investment	350			500			740			500
Impairment of assets	476			—			476			193
Other, net (1)	240			(66		)	964			314
Adjusted EBITDA	$	14,834		$	23,573		$	51,129		$	58,991
Cash interest, net of capitalized costs	(8,035		)	(7,750		)	(26,197		)	(21,317		)
Income tax benefit	—			190			2			112
Maintenance capital expenditures	(969		)	(3,351		)	(4,081		)	(8,968		)
Distributable cash flow	$	5,830		$	12,662		$	20,853		$	28,818

(1) These amounts include an immaterial amount related to the effects of presenting our financial results on an as-if pooled basis (in connection with the 2015 Holdings Acquisition discussed in Note 2 to our condensed consolidated financial statements).

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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,
	2016			2015			2016			2015
Revenues:
Revenues	$	123,043		$	147,114		$	316,673		$	471,735
Revenues - affiliates	21,619			32,455			72,418			60,993
Total revenues	144,662			179,569			389,091			532,728
Expenses:
Cost of natural gas and liquids sold	108,572			133,401			273,638			399,111
Operations and maintenance	17,781			19,139			54,173			61,528
Depreciation and amortization	31,449			17,853			68,898			52,456
General and administrative	6,831			6,803			22,879			23,612
Impairment of assets	476			—			476			193
Loss (gain) on sale of assets, net	(179		)	(33		)	(12,755		)	146
Total expenses	164,930			177,163			407,309			537,046

Income (loss) from operations	(20,268		)	2,406			(18,218		)	(4,318		)
Other expense:
Equity in losses of joint venture investments	(3,694		)	(3,567		)	(10,656		)	(10,722		)
Interest expense	(8,598		)	(8,688		)	(26,601		)	(24,087		)
Total other expense	(12,292		)	(12,255		)	(37,257		)	(34,809		)
Loss before income tax benefit	(32,560		)	(9,849		)	(55,475		)	(39,127		)
Income tax benefit	—			190			2			113
Net loss	$	(32,560	)	$	(9,659	)	$	(55,473	)	$	(39,014	)

Other financial data:
Adjusted EBITDA	$	14,834		$	23,573		$	51,129		$	58,991

Maintenance capital expenditures	$	969		$	3,351		$	4,081		$	8,968
Growth capital expenditures	$	3,926		$	25,636		$	13,248		$	84,978

Operating data:
Average volume of processed gas (MMcf/d)	299			441			320			432
Average volume of NGLs produced (Bbls/d)	29,675			43,541			35,043			42,031
Average daily throughput Mississippi/Alabama (MMcf/d)	136			216			146			234

Realized prices on natural gas volumes ($/Mcf)	$	2.76		$	3.61		$	2.15		$	3.07
Realized prices on NGL volumes ($/gal)	0.41			0.34			0.34			0.38

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Three Months Ended September 30, 2016 Compared to Three Months Ended September 30, 2015

Volume and overview. Processed gas volumes decreased 142 MMcf/d, or 32%, to 299 MMcf/d during the three months ended September 30, 2016, compared to 441 MMcf/d during the three months ended September 30, 2015. This decrease was due primarily to a continued low commodity price environment for natural gas, crude oil and NGLs and a few customers electing to redirect gas away from our processing facilities.

NGLs produced at our processing plants for the three months ended September 30, 2016 averaged 29,675 Bbls/d, a decrease of 32%, or 13,866 Bbls/d, compared to 43,541 Bbls/d for the three months ended September 30, 2015. The decrease in NGLs produced is due primarily to a decline in processed gas volumes, as well as higher ethane rejection rates in August and September of 2016.

Revenues. Our total revenues for the three months ended September 30, 2016 decreased $34.9 million, or 19%, to $144.7 million compared to $179.6 million for the three months ended September 30, 2015. This decrease was due primarily to a decrease in realized prices in natural gas and NGLs, as well as a decrease in processed gas volumes resulting in revenue from sales of natural gas decreasing by $27.4 million for the three months ended September 30, 2016 compared to the three months ended September 30, 2015.

Cost of natural gas and NGLs sold. Our cost of natural gas and NGLs sold for the three months ended September 30, 2016 was $108.6 million, compared to $133.4 million for the three months ended September 30, 2015. This decrease of $24.8 million, or 19%, was due primarily to lower processed gas volumes and lower natural gas and NGL prices compared to the same period in 2015.

Operations and maintenance expenses. Operations and maintenance expenses for the three months ended September 30, 2016 were $17.8 million, compared to $19.1 million for the three months ended September 30, 2015 for a decrease of $1.3 million, or 7%. This decrease was due primarily to improved operating efficiencies at our facilities.

General and administrative expenses. General and administrative expenses for the three months ended September 30, 2016 and 2015 were $6.8 million, respectively.

Depreciation and amortization expense. Depreciation and amortization expense for the three months ended September 30, 2016 was $31.4 million, compared to $17.9 million for the three months ended September 30, 2015. The increase of $13.5 million, or 75%, was due primarily to accelerating the depreciation of our Conroe and Gregory facilities beginning August 2016 in response to management’s plans to shut down the Conroe facility and convert the Gregory facility to a compressor station by December 31, 2016.

Equity in losses of joint venture investments. Our share of losses incurred by joint venture investments was $3.7 million for the three months ended September 30, 2016 and $3.6 million for the three months ended September 30, 2015. We pay our proportionate share of the joint ventures’ operating costs, excluding depreciation and amortization, through lease capacity payments. As a result, our share of the joint ventures’ losses is related primarily to the joint ventures’ depreciation and amortization.

Interest expense. For the three months ended September 30, 2016, interest expense was $8.6 million, compared to $8.7 million for the three months ended September 30, 2015. This decrease of $0.1 million was due primarily to lower average borrowings.

Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015

Volume and overview. Processed gas volumes decreased 112 MMcf/d, or 26%, to 320 MMcf/d during the nine months ended September 30, 2016, compared to 432 MMcf/d during the nine months ended September 30, 2015. This decrease was due primarily to a continued low commodity price environment for natural gas, crude oil and NGLs, the customer elections discussed above and a fire at Holdings’ Lancaster gas treating facility in February 2016 which caused an outage through April 2016.

NGLs produced at our processing plants for the nine months ended September 30, 2016 averaged 35,043 Bbls/d, a decrease of 6,988 Bbls/d, or 17% compared to 42,031 Bbls/d for the nine months ended September 30, 2015. The decrease in NGLs produced is due primarily to a decline in processed gas volumes, as well as an outage at Holdings’ Lancaster gas treating facility as noted above.

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Revenues. Our total revenues for the nine months ended September 30, 2016 decreased $143.6 million, or 27%, to $389.1 million compared to $532.7 million for the nine months ended September 30, 2015. This decrease was due primarily to a decrease in realized prices in natural gas and NGLs, as well as a decrease in processed gas volumes resulting in revenue from sales of natural gas decreasing by $116.7 million, revenue from sales of NGLs and condensate decreasing by $7.7 million and fee based transportation and processing revenue decreasing by $18.9 million for the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015.

Cost of natural gas and NGLs sold. Our cost of natural gas and NGLs sold for the nine months ended September 30, 2016 was $273.6 million, compared to $399.1 million for the nine months ended September 30, 2015. This decrease of $125.5 million, or 31%, was due primarily to lower processed gas volumes and lower natural gas and NGL prices compared to the same period in 2015.

Operations and maintenance expenses. Operations and maintenance expenses for the nine months ended September 30, 2016 were $54.2 million, compared to $61.5 million for the nine months ended September 30, 2015. This decrease of $7.3 million, or 12%, was due primarily to lower plant and pipeline operating expenses from cost saving and reliability initiatives.

General and administrative expenses. General and administrative expenses for the nine months ended September 30, 2016 were $22.9 million, compared to $23.6 million for the nine months ended September 30, 2015 for a decrease of $0.7 million, or 3%. This decrease was due primarily to lower employee labor costs of $1.1 million, partially offset by higher contract labor expenses of $0.3 million.

Depreciation and amortization expense. Depreciation and amortization expense for the nine months ended September 30, 2016 was $68.9 million, compared to $52.5 million for the nine months ended September 30, 2015. The increase of $16.4 million, or 31%, was due primarily to accelerating the depreciation of our Conroe facility and Gregory facility assets beginning August 2016 in response to management’s plans to shut down the Conroe facility and convert the Gregory facility to a compressor station by December 31, 2016.

Equity in losses of joint venture investments. Our share of losses incurred by joint venture investments was $10.7 million for the nine months ended September 30, 2016 and 2015, respectively. We pay our proportionate share of the joint ventures’ operating costs, excluding depreciation and amortization, through lease capacity payments. As a result, our share of the joint ventures’ losses is related primarily to the joint ventures’ depreciation and amortization.

Interest expense. For the nine months ended September 30, 2016, interest expense was $26.6 million, compared to $24.1 million for the nine months ended September 30, 2015. This increase of $2.5 million was due primarily to higher average borrowings and higher interest rates on borrowings.

Liquidity and Capital Resources

Sources of Liquidity

Our primary sources of liquidity are cash generated from operations, cash raised through issuances of additional equity and debt securities and borrowings under our Senior Credit Facilities (as defined in Note 6 to our condensed consolidated financial statements). Our primary cash requirements consist of operating and maintenance and general and administrative expenses, growth and maintenance capital expenditures to sustain existing operations or generate additional revenues, interest payments on outstanding debt, purchases and construction of new assets, business acquisitions and distributions to unitholders.

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

Our future cash flow will be materially adversely affected if the prolonged deterioration of natural gas, NGL and crude oil prices continues or if the reduction in drilling for oil or natural gas continues in the geographic areas in which we operate, primarily the Eagle Ford Shale region. See Note 1 to our condensed consolidated financial statements. The majority of our revenue is derived from fixed-fee and fixed-spread contracts, which have limited direct exposure to commodity price levels since we are paid based on the volumes of natural gas that we gather, process, treat, compress and transport and the volumes of NGLs we fractionate and transport, rather than being paid based on the value of the underlying natural gas or NGLs. In

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addition, a portion of our contract portfolio contains minimum volume commitment arrangements. The majority of our volumes are dependent upon the level of producer drilling activity. With the current price environment and reduction in drilling activity, we have begun to implement cost saving initiatives to improve future cash flows.

After considering these uncertainties, our forecast indicates future shortfalls in the amount of consolidated EBITDA (as defined in the Third Amended and Restated Revolving Credit Agreement with Wells Fargo, N.A., UBS Securities LLC and Barclays Bank PLC and a syndicate of lenders (the “Third A&R Revolving Credit Agreement”), as amended in May 2015) necessary to remain in compliance with the consolidated total leverage ratio of our Financial Covenants (as defined in Note 6 to our condensed consolidated financial statements) in our Credit Facility (defined below) for the remainder of 2016 and continuing into 2017. As discussed in further detail in Note 6 to our condensed consolidated financial statements, we have the right to cure such a Financial Covenant Default (as defined in Note 6 to our condensed consolidated financial statements) by either our Sponsors or Holdings purchasing equity interests in or making capital contributions (an equity cure) resulting in, among other things, proceeds that, if added to consolidated EBITDA, would result in us satisfying the Financial Covenants. Once such an equity cure is made, it is included in our consolidated EBITDA calculation in any rolling twelve month period that includes the quarter that was cured. Should there be an event of default under the Credit Facility, and such default is not cured, we also would experience a cross default under our Term Loan Agreement (defined in Note 6 to our condensed consolidated financial statements) and all of our debt would become due and payable to our lenders.

On March 17, 2016, we entered into the Equity Cure Agreement with Holdings whereby we have the right to cure any default with respect to our Financial Covenants by having Holdings purchase equity interests in or make capital contributions to us, in an aggregate amount of up to $50 million. The fair value of the Equity Cure Agreement was not material at inception. In connection with Holdings' Chapter 11 reorganization, and pursuant to the terms of the Equity Cure Agreement, Holdings has committed to contribute up to $50 million to us (the “Contribution Amount”) to comply with applicable Financial Covenants through the quarter ended December 31, 2016. In exchange for the Contribution Amount, we will issue Holdings a number of our common units representing limited partner interests equal to, subject to certain exceptions, (i) the applicable Contribution Amount divided by (ii) a common unit reference price (“Reference Price”) equal to the volume weighted daily average price of the common units on the New York Stock Exchange (“VWAP”) calculated for a period of 15 trading days ending two trading days prior to the contribution by Holdings. Notwithstanding the VWAP calculation, the Reference Price will be no less than $0.89 per common unit and no greater than $1.48 per common unit.

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


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


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

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Maintenance capital expenditures	$	969	$	3,351	$	4,081	$	8,968
Growth capital expenditures	3,926		25,636		13,248		84,978
Capital expenditures	$	4,895	$	28,987	$	17,329	$	93,946

Our growth capital expenditures during the nine months ended September 30, 2016 relate primarily to various expansion and improvement projects primarily in our South Texas assets. The growth capital expenditures during the nine months ended September 30, 2015 related primarily to the construction of the Valley Wells sour gas gathering and treating system and the compression assets that are part of the Valley Wells and Lancaster gathering and treating systems, and the timing of payments, $9.7 million of which related to 2014 activity that were paid in 2015, as well as various expansion and improvement projects primarily in our South Texas assets.

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

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

We believe that cash from operations, cash on hand and the sale of equity to Holdings under the Contribution Amount will provide sufficient liquidity to meet future short-term capital requirements for a reasonable period of time. The sufficiency of these liquidity sources to fund necessary and committed capital needs will be dependent upon our ability to meet our covenant requirements of our Senior Credit Facilities. The Partnership is currently in active and constructive discussions with its lenders regarding a potential amendment to the Financial Covenants and terms contained in our Third A&R Revolving Credit Agreement. An amendment to the Financial Covenants requires the approval of lenders representing over 50% of the total revolving credit exposure. Should such an amendment not occur, we expect that additional equity cures will be required to maintain compliance with our Financial Covenants for the quarter ended December 31, 2016. If the Sponsors, either directly or through Holdings, elect not to fund the necessary additional equity cures to maintain compliance with our Financial Covenants, then we may need to seek other alternatives in order to operate our business. See Notes 1 and 6 to our condensed consolidated financial statements.

Growth projects and acquisitions are key elements of our business strategy. We intend to finance our growth capital through several sources, including operating cash flows, borrowings under our Senior Credit Facilities and issuance of additional debt and equity securities. The timing, size or success of any acquisition or expansion effort and the associated potential capital commitments are unpredictable. To consummate acquisitions or capital projects, we may require access to

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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,
	2016			2015
Net cash provided by operating activities	$	41,203		$	24,508
Net cash used in investing activities	(1,797		)	(109,209		)
Net cash provided by (used in) financing activities	(46,639		)	84,703

Operating cash flows — Net cash provided by operating activities for the nine months ended September 30, 2016 was $41.2 million, compared to $24.5 million for the nine months ended September 30, 2015. The increase of $16.7 million was primarily the result of increased cash received on accounts receivable, including affiliates, and less cash applied toward accounts payable during the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015.

Investing cash flows — Net cash used in investing activities for the nine months ended September 30, 2016 was $1.8 million, compared to $109.2 million for the nine months ended September 30, 2015. The decrease of $107.4 million primarily relates to decreased capital expenditures and acquisitions of $91.6 million during the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015, and higher net cash proceeds received from sales of assets of $16.0 million during the nine months ended September 30, 2016.

Financing cash flows — Net cash used in financing activities for the nine months ended September 30, 2016 was $46.6 million, compared to net cash provided by financing activities of $84.7 million for the nine months ended September 30, 2015. The decrease of $131.3 million was primarily due to reduced net borrowings of $164.1 million from our debt instruments, partially offset by $12.4 million for fourth quarter 2015 and first quarter 2016 equity cures provided by Holdings to us during the nine months ended September 30, 2016.

Off-Balance Sheet Arrangements

We have no off-balance sheet financing arrangements.

Recent Accounting Pronouncements

For discussion on specific recent accounting pronouncements affecting us, please see Note 1 to our unaudited condensed consolidated financial statements under Part I, Item 1 of this report.

Critical Accounting Policies and Estimates

Our critical accounting policies are consistent with those described in our 2015 Annual Report on Form 10-K.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

Our interest rate risk and commodity price, market and credit risks are discussed in our 2015 Annual Report on Form 10-K and there have been no material changes in those exposures from December 31, 2015 to September 30, 2016.

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.

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Internal control over financial reporting. There were no changes in our system of internal control over financial reporting (as defined in Rule 13a—15(f) or Rule 15d—15(f) of the Exchange Act) during the third quarter of 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

From time to time, we may be involved in various legal or governmental proceedings and litigation arising in the ordinary course of business. In management’s opinion, the resolution of such matters is not expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows. See Note 7 to our condensed consolidated financial statements.

Item 1A. Risk Factors.

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

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

As discussed in Note 3 to our condensed consolidated financial statements, on August 10, 2016, we issued Class B PIK Units (as defined in Note 3) to the holder of the Class B Convertible Units as a paid-in-kind distribution attributable to the quarter ended June 30, 2016. In connection with the issuance of the Class B PIK Units, our General Partner made a capital contribution in exchange for the issuance of 5,901 general partner units to maintain its 2.0% ownership interest in us.

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

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

None.

Item 5. Other Information.

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

The foregoing descriptions are not complete and are qualified in their entirety by reference to the full text of both the Limited Waiver and Second Amendment and the Waiver and Third Amendment to the Third A&R Revolving Credit Agreement, which is filed as Exhibit 10.1 and Exhibit 10.2 to this Quarterly Report on Form 10-Q and incorporated herein by reference.

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Item 6. Exhibits.

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

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SIGNATURES

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



		SOUTHCROSS ENERGY PARTNERS, L.P.

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


Date:	November 9, 2016	By:	/s/ Bret M. Allan
			Bret M. Allan
			Senior Vice President and Chief Financial Officer
			(Principal Financial Officer)

Date:	November 9, 2016	By:	/s/ G. Tracy Owens
			G. Tracy Owens
			Vice President and Chief Accounting Officer
			(Principal Accounting Officer)

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		EXHIBIT INDEX
Exhibit
Number		Description
3.1		Certificate of Limited Partnership of Southcross Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).
3.2		Third Amended and Restated Agreement of Limited Partnership of Southcross Energy Partners, L.P., dated as of August 4, 2014 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated August 4, 2014).
3.3		Certificate of Formation of Southcross Energy Partners GP, LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).
3.4		Second Amended and Restated Limited Liability Company Agreement of Southcross Energy Partners GP, LLC, dated as of August 4, 2014 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K dated August 4, 2014).
4.1		Registration Rights Agreement, dated as of April 12, 2013, by and between Southcross Energy Partners, L.P. and Southcross Energy LLC (incorporated by reference to Exhibit 4.1 to our Annual Report on Form 10-K for the fiscal year ending December 31, 2012).
10.1		Limited Waiver and Second Amendment to Third Amended and Restated Revolving Credit Agreement, by and among the Partnership, as borrower, Wells Fargo Bank, N.A., as Administrative Agent, and the lenders and other parties thereto, dated as of August 4, 2016 (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2016).
10.2*		Waiver and Third Amendment to Third Amended and Restated Revolving Credit Agreement, by and among the Partnership, as borrower, Wells Fargo Bank, N.A., as Administrative Agent, and the lenders and other parties thereto, dated as of November 8, 2016.
31.1*		Certification of Chief Executive Officer required by Rule 13a-14(a)/15d-14(a).
31.2*		Certification of Chief Financial Officer required by Rule 13a-14(a)/15d-14(a).
32.1**		Certifications of Chief Executive Officer and Chief Financial Officer required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
101.INS*†		XBRL Instance Document.
101.SCH*†		XBRL Taxonomy Extension Schema.
101.CAL*†		XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*†		XBRL Taxonomy Extension Definition Linkbase.
101.LAB*†		XBRL Taxonomy Extension Label Linkbase.
101.PRE*†		XBRL Extension Presentation Linkbase.

* Filed herewith.

** Furnished herewith.

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

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Southcross Energy Partners Inactive 10-Q2016 Q3 Quarterly report

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