Southcross Energy Partners 8-K 20 Aug 15 Other Events Financial data

Document and Entity Information

Document and Entity Information	3 Months Ended
	Mar. 31, 2015
Document and Entity Information
Entity Registrant Name	Southcross Energy Partners, L.P.
Entity Central Index Key	1,547,638
Document Type	8-K
Document Period End Date	Mar. 31, 2015
Amendment Flag	false

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 230	$ 1,649	$ 3,349
Trade accounts receivable	58,356	74,086	57,669
Accounts Receivable, Related Parties	8,882	11,325	0
Prepaid expenses	2,423	3,073	3,061
Other current assets	750	1,813	5,105
Total current assets	70,641	91,946	69,184
Property, plant and equipment, net	1,060,633	1,058,570	575,795
Intangible assets, net	1,497	1,511	1,568
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	145,675	147,098	0
Other assets	16,275	17,189	5,768
Total assets	1,294,721	1,316,314	652,315
Current liabilities:
Accounts payable and accrued liabilities	79,748	116,842	62,451
Due to Affiliate, Current	3,803	12,856	0
Other Long-term Debt, Current	4,500	4,500	0
Other current liabilities	15,139	12,773	5,344
Total current liabilities	103,190	146,971	67,795
Long-term debt		471,129	267,300
Other non-current liabilities	1,392	1,110	1,692
Total liabilities	609,674	$ 619,210	$ 336,787
Commitments and contingencies
Partners' capital:
Accumulated other comprehensive loss	88,776	$ 77,320	$ 0
Partners' capital:
Total partners' capital	685,047	697,104	275,024
Liabilities, preferred units, partners' capital and members' equity:
Total liabilities, preferred units and partners' capital	1,294,721	1,316,314	652,315
Common Units
Partners' capital:
Total partners' capital	243,464	259,735	169,141
Class B Convertible Units [Member]
Partners' capital:
Total partners' capital	299,426	298,833	0
Subordinated Limited Partners [Member]
Partners' capital:
Total partners' capital	41,628	48,831	99,726
General Partner Units [Member]
Partners' capital:
General Partner interest	11,753	12,385	6,367
Partners' capital:
Total partners' capital	$ 11,753	12,385	6,367
Accumulated Other Comprehensive Income (Loss) [Member]
Partners' capital:
Accumulated other comprehensive loss		0	(210)
Series A Convertible Preferred Units [Member]
Preferred units of Southcross Energy LLC:
Series A convertible preferred units (1,769,915 units issued and outstanding as of December 31, 2013)		$ 0	$ 40,504

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2014	Dec. 31, 2013
Partners' capital:
Series A convertible preferred units outstanding	11,850,374
Common Units
Partners' capital:
Limited Partner, units outstanding	23,800,943	12,253,985
Subordinated Limited Partners [Member]
Partners' capital:
Limited Partner, units outstanding	12,213,713	12,213,713
Redeemable
Partners' capital:
Series A convertible preferred units issued	14,889,078	1,769,915
Series A convertible preferred units outstanding	14,889,078	1,769,915

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues	$ 178,491	$ 213,591	$ 835,246	$ 634,722	$ 496,129
Revenue from Related Parties	7,447	0	13,267	0	0
Revenues:	185,938	213,591	848,513	634,722	496,129
Expenses:
Cost of natural gas and liquids sold	141,115	186,403	721,132	541,176	424,489
Operations and maintenance	22,555	10,861	59,915	41,254	35,532
Depreciation and amortization	(17,031)	(8,528)	(46,050)	(33,548)	(18,977)
General and administrative	7,805	6,103	32,723	21,764	13,842
Asset Impairment Charges			1,556	0	0
Gain on sale of assets, net	218	4	365	(25)	0
Costs and Expenses	188,724	211,899	861,741	637,717	492,840
(Loss) income from operations	(2,786)	1,692	(13,228)	(2,995)	3,289
Income (Loss) from Equity Method Investments	(3,552)		(6,496)	0	0
Interest expense	(7,498)	(2,973)	(15,562)	(12,590)	(5,767)
Loss on extinguishment of debt			(2,316)	0	(1,764)
Other Expenses			(77)	0	0
Other Cost and Expense, Operating	11,050	2,973	24,451	12,590	7,531
Loss before income tax expense	(13,836)	(1,281)	(37,679)	(15,585)	(4,242)
Income tax expense	(69)	(8)	(52)	(385)	(246)
Net loss	13,905	1,289	37,731	15,970	4,488
Series A Preferred fair value adjustment	0	33	(4,596)	(1,670)	0
Distribution Made to Member or Limited Partner, Distribution Paid In-kind, Fair Value Disclosure				0
Net loss attributable to partners	$ (10,827)	(1,790)	(36,659)	(17,640)	(4,228)
Less deemed dividend on:
Net loss attributable to Southcross Energy LLC common unitholders			$ 0	$ 0	$ (22,910)
Earnings per unit:
Distribution Made to Member or Limited Partner Minimum Quarterly Distributions Declared Per Unit	$ 0.40
Weighted average number of Southcross Energy LLC common units outstanding			0	0	1,198,429
Basic and diluted net loss per Southcross Energy LLC common unit			$ (0.93)		$ (0.17)
General Partner [Member]
Expenses:
Net loss	$ 217	26	$ 626	$ 319
Series A Preferred fair value adjustment				(1,670)
Distribution Made to Member or Limited Partner, Distribution Paid In-kind, Fair Value Disclosure	(76)	0	(207)	(33)
Common Units
Expenses:
Net loss	4,902	757	15,155	7,829
Distribution Made to Member or Limited Partner, Distribution Paid In-kind, Fair Value Disclosure				(17)
Less deemed dividend on:
Net loss attributable to Southcross Energy LLC common unitholders	(4,936)	(1,045)	(20,175)		$ (2,072)
Net income (loss) allocated to limited partners	$ (4,936)	$ (1,045)	$ (20,175)	$ (8,683)	$ (2,072)
Earnings per unit:
Weighted average number of partner units outstanding (in shares)	23,801,000	18,285,000	21,641,635	12,224,997	12,213,713
Loss per unit (in dollars per share)	$ (0.21)	$ (0.06)	$ (0.93)	$ (0.71)	$ (0.17)
Basic and diluted net loss per Southcross Energy LLC common unit	$ (0.21)	$ (0.06)
Subordinated Limited Partners [Member]
Expenses:
Net loss	$ 2,513	$ 506	$ 8,105	$ 7,822
Distribution Made to Member or Limited Partner, Distribution Paid In-kind, Fair Value Disclosure				(16)
Less deemed dividend on:
Net loss attributable to Southcross Energy LLC common unitholders	(2,533)	(719)
Net income (loss) allocated to limited partners	$ (2,533)	$ (719)	$ (8,355)	$ (8,638)	$ (2,071)
Earnings per unit:
Weighted average number of partner units outstanding (in shares)	12,214,000	12,214,000	12,213,713	12,213,713	12,213,713
Loss per unit (in dollars per share)	$ (0.21)	$ (0.06)	$ (0.68)	$ (0.71)	$ (0.17)
Basic and diluted net loss per Southcross Energy LLC common unit	$ (0.21)	(0.06)
Southcross Energy LLC [Member]
Earnings per unit:
Basic and diluted net loss per Southcross Energy LLC common unit					$ (19.12)
Southcross Holdings Common [Member]
Expenses:
Net loss attributable to partners	$ (3,154)		$ (6,409)
Redeemable
Less deemed dividend on:
Preferred units					$ (2,693)
Series B
Less deemed dividend on:
Preferred units					(4,696)
Series C
Less deemed dividend on:
Preferred units					(2,012)
Preferred
Less deemed dividend on:
Preferred units					$ (13,249)
Cash Distribution [Member]
Earnings per unit:
Distribution Made to Member or Limited Partner Minimum Quarterly Distributions Declared Per Unit	$ 0.4	$ 0.4	$ 0.40
Cash Distribution [Member] | Common Units | Limited Partners [Member]
Earnings per unit:
Distribution Made to Member or Limited Partner Minimum Quarterly Distributions Declared Per Unit			$ 1.60	$ 1.60	$ 0.24
Series A Convertible Preferred Units [Member]
Expenses:
Series A Preferred fair value adjustment	$ 0	$ 33	$ (4,596)	$ (37)
Dividends, Preferred Stock, Paid-in-kind	$ 0	$ (534)	$ (534)	$ (1,633)
Earnings per unit:
Distribution Made to Member or Limited Partner Minimum Quarterly Distributions Declared Per Unit	$ 0.40

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Net loss	$ (13,905)	$ (1,289)	$ (37,731)	$ (15,970)	$ (4,488)
Other comprehensive income (loss):
Hedging losses reclassified to earnings and recognized in interest expense	0	115	221	415	268
Adjustment in fair value of derivatives	0	(11)	(11)	(148)	(745)
Total other comprehensive income (loss)	0	104	210	267	(477)
Comprehensive loss	$ (13,905)	$ (1,185)	$ (37,521)	$ (15,703)	$ (4,965)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:
Net loss	$ (13,905)	$ (1,289)	$ (37,731)	$ (15,970)	$ (4,488)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization	17,031	8,528	46,050	33,548	18,977
Unit-based compensation	813	529	10,074	2,186	630
Loss on extinguishment of debt			2,316	0	1,764
Amortization of Financing Costs and Discounts	737	337	2,005
Amortization of deferred financing costs	825	337	4,192	1,287	1,183
Loss (gain) on sale of assets, net	218	4	365	(25)
Unrealized (gain) loss	167	(32)	168	(120)	141
Income (Loss) from Equity Method Investments, Net of Dividends or Distributions	3,552	0	6,496	0	0
Asset Impairment Charges			1,556	0	0
Other, net	11	14	65	130	0
Changes in operating assets and liabilities:
Trade accounts receivable, including affiliates	18,307	(7,477)	(24,770)	(6,675)	(9,760)
Prepaid expenses and other current assets	(297)	813	(5)	(1,197)	(1,246)
Other non-current assets	170	(25)	(29)	215	1,786
Accounts payable and accrued liabilities	(27,140)	13,694	35,658	1,411	16,517
Other liabilities, including affiliates	2,296	(920)	3,410	1,183	(1,181)
Net cash provided by operating activities	2,048	14,176	45,628	15,973	24,323
Cash flows from investing activities:
Capital expenditures	(41,002)	(11,087)	(168,617)	(93,863)	(169,816)
Expenditures for assets subject to property damage claims, net of insurance proceeds and deductibles	545	(693)	2,706	(3,383)	0
Acquisition of Enterprise Alabama Intrastate, LLC	0	(38,636)	(44,038)	0	0
Payments to Acquire Interest in Joint Venture	(2,349)	0	(148)	0	0
Payments to Acquire Businesses and Interest in Affiliates			(79,955)	0	0
Proceeds from sale of assets	4,368		1,625	137
Net cash used in investing activities	(38,438)	(50,416)	(288,427)	(97,109)	(169,816)
Cash flows from financing activities:
Proceeds from issuance of common units, net					187,764
Borrowings under our credit facility	50,000	62,000	244,500	129,300	297,500
Proceeds from Issuance of Other Long-term Debt			450,000	0	0
Repayments under our credit facility	(15,000)	(158,450)	(481,800)	(53,000)	(314,780)
Repayments of Other Long-term Debt	(1,125)	0	(2,250)	0	0
Payments on capital lease obligations	(140)	(143)	(599)	(542)	0
Financing costs	(6)	(156)	(17,777)	(2,139)	(5,178)
Proceeds from issuance of Series A convertible preferred units, net of issuance costs			0	38,832	0
Distributions to Southcross Energy LLC					(46,030)
Payments of distributions and distribution equivalent rights	(13,368)	(13,755)	(52,645)	(35,992)	0
Proceeds from (Repayments of) Related Party Debt			(100,000)	0	0
Tax withholdings on unit-based compensation vested units	0	(1)	(3,532)	(264)	0
Affiliate Costs	14,610	0	50,564
Net cash provided by financing activities	34,971	37,325	241,099	76,995	151,571
Cash and Cash Equivalents, Period Increase (Decrease)	(1,419)	1,085	(1,700)	(4,141)	6,078
Cash and cash equivalents — Beginning of year	1,649	3,349	3,349	7,490	1,412
Cash and cash equivalents — End of year	230	4,434	1,649	3,349	7,490
Repurchase and retirement of Southcross Energy LLC common units			144,671
Common Units
Cash flows from operating activities:
Net loss	(4,902)	(757)	(15,155)	(7,829)
Cash flows from financing activities:
Repurchase and retirement of Southcross Energy LLC common units		144,715	144,671
General Partner [Member]
Cash flows from operating activities:
Net loss	$ (217)	(26)	(626)	(319)
Cash flows from financing activities:
Proceeds from Partnership Contribution			$ 9,967	$ 800	0
Repurchase and retirement of Southcross Energy LLC common units		$ 0
Series B
Cash flows from financing activities:
Proceeds from issuance of preferred units					(42,800)
Series C
Cash flows from financing activities:
Proceeds from issuance of preferred units					(30,000)
Common Units
Cash flows from financing activities:
Purchase and retirement of common units					(25,205)
Common units [Member]
Cash flows from financing activities:
Purchase and retirement of common units					$ (15,300)

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL AND MEMBERS' EQUITY - USD ($)	Total	Class B Convertible Units [Member]	Class B Convertible Units	Series B redeemable preferred units	Series C redeemable preferred units	Preferred units	Series A preferred units	Common units [Member]Common Class A	Common units [Member]Common Class B [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss	Southcross Holdings Common [Member]	Southcross Holdings Common [Member]Class B Convertible Units [Member]	General Partner [Member]	General Partner [Member]Series A preferred units	Common Units	Common UnitsClass B Convertible Units [Member]	Common UnitsSeries A preferred units	Class B Convertible Units [Member]	Subordinated Limited Partners [Member]	Subordinated Limited Partners [Member]Series A preferred units	valley wells [Member]	valley wells [Member]Southcross Holdings Common [Member]	valley wells [Member]General Partner [Member]	valley wells [Member]Common Units	valley wells [Member]Class B Convertible Units [Member]	valley wells [Member]Subordinated Limited Partners [Member]
BALANCE-Members' Equity at Dec. 31, 2011	$ (10,165,000)							$ 1,416,000	$ 57,000	$ (11,638,000)	$ 0			$ 0		$ 0				$ 0
BALANCE-Partners' Capital at Dec. 31, 2011																			$ 0
Increase (Decrease) in Shareholders' Equity
Net loss	(4,488,000)
Series A convertible preferred unit in-kind distribution and fair value adjustments	0
Deemed dividend on:
Preferred units			$ (2,693,000)	$ (4,696,000)	$ (2,012,000)	$ (13,249,000)
BALANCE-Members' Equity at Dec. 31, 2012	326,467,000							0	0	0	(477,000)			6,628,000		194,364,000				125,952,000
BALANCE-Partners' Capital at Dec. 31, 2012																			0
Increase (Decrease) in Shareholders' Equity
Net loss	(15,970,000)													(319,000)		(7,829,000)				(7,822,000)
Series A convertible preferred unit in-kind distribution and fair value adjustments	(1,670,000)													(1,670,000)	$ (33,000)			$ (838,000)			$ (799,000)
Contributions from general partner	(800,000)													(800,000)		0				0
Deemed dividend on:
Purchase and retirement of Partnership common units							$ 1,601,000											1,601,000
Distribution to partners	(35,928,000)													(742,000)		(17,597,000)				(17,589,000)
Accrued distribution equivalent rights on long-term incentive plan	(279,000)															(279,000)
Tax withholdings on unit-based compensation vested units	(264,000)															(264,000)
Distribution Made to Member or Limited Partner, Distribution Paid In-kind, Fair Value Disclosure	0													(33,000)		(17,000)				(16,000)
Net effect of cash flow hedges	267,000										267,000
BALANCE-Partners' Capital at Dec. 31, 2013	275,024,000							0	0	0	(210,000)			6,367,000		169,141,000			0	99,726,000
Deemed dividend on:
Accrued Distribution on Long Term Incentive Plan	(279,000)
Net loss	(1,289,000)										0			(26,000)		(757,000)				(506,000)
Series A convertible preferred unit in-kind distribution and fair value adjustments	33,000
Contributions from general partner	0										0			11,000		(6,000)				(5,000)
Preferred units	3,115,000										0			(3,115,000)		0				0
Repurchase and retirement of Southcross Energy LLC common units											144,715,000			0		144,715,000			0	0
Contribution by Southcross Energy LLC	(502,000)										0				(11,000)			$ (281,000)			(210,000)
Purchase and retirement of Partnership common units	432,000										0			0		432,000					0
Distribution to partners	(13,755,000)										0			(289,000)		(8,581,000)				(4,885,000)
Tax withholdings on unit-based compensation vested units											(1,000)			0		(1,000)			0	0
Distribution Made to Member or Limited Partner, Distribution Paid In-kind, Fair Value Disclosure														0
Net effect of cash flow hedges	104,000										104,000			0		0				0
BALANCE-Partners' Capital at Mar. 31, 2014	407,767,000										(106,000)			9,167,000		304,586,000				94,120,000
Deemed dividend on:
Accrued Distribution on Long Term Incentive Plan	(76,000)										0			0		(76,000)				0
BALANCE-Partners' Capital at Dec. 31, 2013	275,024,000							$ 0	$ 0	$ 0	(210,000)			6,367,000		169,141,000			0	99,726,000
Increase (Decrease) in Shareholders' Equity
Net loss	(37,731,000)											$ (6,409,000)		(626,000)		(15,155,000)			(7,436,000)	(8,105,000)
Series A convertible preferred unit in-kind distribution and fair value adjustments	(4,596,000)														(208,000)		$ (6,209,000)		9,610,000		(3,193,000)
Contributions from general partner	0													(222,000)		(142,000)				(80,000)
Deemed dividend on:
Preferred units	(11,316,000)													(9,991,000)		(809,000)			(171,000)	(345,000)
Repurchase and retirement of Southcross Energy LLC common units	144,671,000															144,671,000
Contribution by Southcross Energy LLC	(5,130,000)													(107,000)		(3,126,000)				(1,897,000)
Purchase and retirement of Partnership common units	9,947,000															9,947,000
Distribution to partners	(52,645,000)													(1,282,000)		(36,706,000)				(14,657,000)
Tax withholdings on unit-based compensation vested units	(3,532,000)															(3,532,000)
Distribution Made to Member or Limited Partner, Distribution Paid In-kind, Fair Value Disclosure														(207,000)
Net effect of cash flow hedges	210,000										210,000
BALANCE-Partners' Capital at Dec. 31, 2014	697,104,000										$ 0	77,320,000		12,385,000		259,735,000			298,833,000	48,831,000			$ 77,320,000
Deemed dividend on:
Proceeds from Issuance of Convertible Preferred Stock	324,413,000																0		324,413,000
Business Combination, Consideration Transferred	(98,625,000)													(1,972,000)		(45,420,000)			(27,925,000)	(23,308,000)
Series A Convertible preferred unit in-kind distributions and fair value adjustments	45,624,000															45,624,000
Accrued Distribution on Long Term Incentive Plan	(167,000)															(167,000)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net												33,165,000
Business Acquisition, Transaction Costs																							50,564,000
Net loss	(13,905,000)											(3,154,000)		(217,000)		(4,902,000)			(3,119,000)	(2,513,000)
Series A convertible preferred unit in-kind distribution and fair value adjustments	0												$ 0		$ (75,000)		$ (2,405,000)		3,712,000		(1,232,000)
Contributions from general partner	0											0		76,000		(50,000)			0	(26,000)
Preferred units	0
Purchase and retirement of Partnership common units	948,000											0		0		948,000			0		$ 0
Distribution to partners	(13,368,000)	$ (0.44)										0		(416,000)		(9,520,000)			0	(3,432,000)
Distribution Made to Member or Limited Partner, Distribution Paid In-kind, Fair Value Disclosure														(76,000)
BALANCE-Partners' Capital at Mar. 31, 2015	685,047,000											88,776,000		11,753,000		243,464,000			299,426,000	41,628,000
Deemed dividend on:
Accrued Distribution on Long Term Incentive Plan	(342,000)											$ 0		$ 0		$ (342,000)			$ 0	$ 0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	$ 88,800,000
Business Acquisition, Transaction Costs																						$ 14,610,000	$ 14,610,000	$ 0	$ 0	$ 0	$ 0

ORGANIZATION AND DESCRIPTION OF

ORGANIZATION AND DESCRIPTION OF BUSINESS	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION AND DESCRIPTION OF BUSINESS	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.” Until August 4, 2014, Southcross Energy LLC, a Delaware limited liability company, held all of the equity interests in Southcross Energy Partners GP, LLC, a Delaware limited liability company, and our general partner (“General Partner”), all of our subordinated units and a portion of our common units. Southcross Energy LLC is controlled through investment funds and entities associated with Charlesbank Capital Partners, LLC (“Charlesbank”). Holdings Transaction On August 4, 2014, Southcross Energy LLC and TexStar Midstream Services, LP, a Texas limited partnership (“TexStar”), combined pursuant to a contribution agreement in which Southcross Holdings LP, a Delaware limited partnership (“Holdings”), was formed (the “Holdings Transaction”). As a result of the Holdings Transaction, Holdings indirectly owns 100% of our General Partner (and therefore controls us), all of our subordinated units and a portion of our common units. Our General Partner owns an approximate 2.0% interest in us and all of our incentive distribution rights. Charlesbank, EIG Global Energy Partners, LLC (“EIG”) and Tailwater Capital LLC (“Tailwater”) (collectively, the “Sponsors”) each indirectly own approximately one-third of Holdings. Affiliates of Energy Capital Partners Mezzanine Opportunities Fund and GE Energy Financial Services also own certain additional equity interests in Holdings. TexStar Rich Gas System Transaction Contemporaneously with the closing of the Holdings Transaction, TexStar contributed to us certain gathering and processing assets (the “TexStar Rich Gas System”), which were owned by TexStar (the “TexStar Rich Gas System Transaction”). For additional details regarding the Holdings Transaction and the TexStar Rich Gas System Transaction, see Notes 2, 6, 9, 10, and 13. Holdings Drop-Down Acquisition On May 7, 2015, we acquired gathering, treating, compression and transportation assets (the “2015 Holdings Acquisition”) from Holdings and its subsidiaries 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 that were under construction at the time of the transaction (and that are now operational). For additional details regarding the 2015 Holdings Acquisition, see Notes 2 and 9. Liquidity Consideration Beginning in the second half of 2014 and continuing through the issuance of our financial statements, commodity prices have experienced increased volatility. In particular, natural gas, crude oil and NGL prices have decreased significantly. If a material reduction in drilling occurs in the geographic areas in which we operate, including the Eagle Ford Shale region, or significant, prolonged pricing deterioration occurs for commodities we sell, our future cash flow may be materially adversely affected. The majority of our revenue is derived from fixed-fee contracts, which have limited direct exposure to commodity price levels since we are paid based on the volumes of natural gas that we gather, process, treat, compress and transport and the volumes of NGLs we fractionate and transport, rather than the value of the underlying natural gas or NGLs, although a percentage of our contract portfolio contains minimum volume commitment arrangements. The majority of our sales volumes are dependent upon the level of producer drilling activity. After considering these uncertainties and in developing our annual budget for 2015, our forecast indicates a potential shortfall in the amount of consolidated EBITDA (as defined in our Credit Facility (as defined in Note 6)) to comply with the consolidated total leverage ratio of our Financial Covenants (as defined in Note 6) in our Credit Facility. As discussed in further detail in Note 6, we have the right (which cannot be exercised more than two times in any 12-month period or more than four times during the term of the facility) to cure such a Financial Covenant Default (as defined in Note 6) by 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 would also 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. In response to the Partnership’s expected need for additional liquidity, our Sponsors (as defined in Note 10) have committed to provide the necessary funding to support the Partnership for at least a reasonable period of time in an amount up to $25 million to ensure the Partnership has sufficient liquidity to comply with its applicable Financial Covenants, and to fund normal operating and growth capital requirements. Therefore, our financial statements have been presented as if the Partnership will continue as a going concern. See Notes 6 and 15. Description of Business We are a master limited partnership 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. We are headquartered in Dallas, Texas. 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. Basis of Presentation We prepared this report under the rules and regulations of the Securities and Exchange Commission 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 the recasted financial statements and financial information filed on a Current Report on Form 8-K on August 20, 2015 (collectively referred herein as the "Recast 2014 Annual Report on Form 10-K"). The condensed consolidated financial statements as of March 31, 2015 and December 31, 2014, and for the three months ended March 31, 2015 and 2014, are unaudited and have been prepared on the same basis as the audited financial statements included in our Recast 2014 Annual Report on Form 10-K. Adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the results of operations and financial position have been included herein. All intercompany accounts and transactions have been eliminated in the preparation of the accompanying condensed consolidated financial statements. The condensed consolidated financial statements reflect the assets acquired and liabilities assumed and the related operating results associated with (i) the Onyx pipelines acquisition beginning on March 6, 2014, (ii) the TexStar Rich Gas System Transaction and the 2015 Holdings Acquisition beginning on August 4, 2014, (iii) and the Texoz acquisition beginning on November 21, 2014. See Note 2. As a result of the Holdings Transaction, Holdings acquired a controlling equity interest in the Partnership, which was accounted for under the acquisition method of accounting in the consolidated financial statements of Holdings, whereby Holdings recorded the Partnership’s assets acquired and liabilities assumed at fair value. However, because less than 80% of the equity interests in the Partnership were acquired, push down accounting of Holdings’ basis in the Partnership was prohibited in our consolidated financial statements. Additionally, because the TexStar Rich Gas System was owned by TexStar, the Partnership recorded the TexStar Rich Gas System at TexStar’s historical cost. Thus, the difference between consideration paid and the TexStar Rich Gas System’s historical cost (net book value) at August 4, 2014, the date on which the Holdings Transaction and the TexStar Rich Gas System Transaction closed, was recorded as a reduction to partners’ capital. Management concluded that the Partnership was the predecessor for accounting purposes for periods prior to August 4, 2014. We recognized the 2015 Holdings Acquisition 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) on May 7, 2015, the date on which the 2015 Holdings Acquisition closed, was recorded as a reduction 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 Recast 2014 Annual Report on Form 10-K. We evaluate events that occur after the balance sheet date, but before the financial statements are issued, for potential recognition or disclosure. Based on the evaluation, we determined that there were no material subsequent events for recognition or disclosure other than those disclosed in this report. Significant Accounting Policies During the first quarter of 2015, there were no material changes to our significant accounting policies described in Note 1 in Part II, Item 8 of our Recast 2014 Annual Report on Form 10-K. Recent Accounting Pronouncements Accounting standard-setting organizations frequently issue new or revised accounting rules. We review new pronouncements to determine their impact, if any, on our consolidated financial statements. We are evaluating the impact of each pronouncement on our consolidated financial statements. In 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. We are currently required to adopt this standard beginning in the first quarter of 2017. On April 1, 2015, the Financial Accounting Standards Board (“FASB”) voted to propose to defer the effective date of the new revenue recognition standard by one year. The FASB plans to disclose its decisions for a 30-day public comment period in a proposed Accounting Standards Update (“ASU”), which is expected to be issued during the second quarter of 2015. In February 2015, the FASB issued an ASU that amended current consolidation guidance with regard to variable interest entities and voting interest entities. All reporting entities will need to re-evaluate and potentially revise their disclosures regarding this topic. This standard will become effective beginning in 2016.	ORGANIZATION, DESCRIPTION OF BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES Organization Southcross Energy Partners, L.P. (the "Partnership," "Southcross," "we," "our" or "us") is a Delaware limited partnership formed in April 2012. Southcross Energy LLC is a Delaware limited liability company, and the predecessor for accounting purposes (the "Predecessor") of the Partnership. References in this Form 10-K to the Partnership, when used for periods prior to our initial public offering ("IPO") on November 7, 2012, refer to Southcross Energy LLC and its consolidated subsidiaries, unless otherwise specifically noted. References in this Form 10-K to the Partnership, when used for periods beginning at or following our IPO, refer collectively to the Partnership and its consolidated subsidiaries. Until August 4, 2014, Southcross Energy LLC held all of the equity interests in Southcross Energy Partners GP, LLC, a Delaware limited liability company and our general partner (“General Partner”), all of our subordinated units, as well as a portion of our common units and Series A Convertible Preferred Units (“Series A Preferred Units”). Southcross Energy LLC is controlled through investment funds and entities associated with Charlesbank Capital Partners, LLC (“Charlesbank”). On August 4, 2014, Southcross Energy LLC and TexStar Midstream Services, LP (“TexStar”) combined pursuant to a contribution agreement in which Southcross Holdings LP, a Delaware limited partnership (“Holdings”), was formed (the “Holdings Transaction”). As a result of the Holdings Transaction, Holdings indirectly owns 100% of our General Partner (and therefore controls us), all of our subordinated units and a portion of our common units. Charlesbank, EIG Global Energy Partners, LLC (“EIG”) and Tailwater Capital LLC (“Tailwater”) (collectively, the “Sponsors”) each indirectly own approximately one-third of Holdings. Affiliates of Energy Capital Partners Mezzanine Opportunities Fund and GE Energy Financial Services own certain additional ownership interests in Holdings as well. On May 7, 2015, we acquired gathering, treating, compression and transportation assets (the “2015 Holdings Acquisition”) from Holdings and its subsidiaries 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 that were under construction at the time of the transaction (and that are now operational). Initial Public Offering On November 7, 2012, we completed our IPO. As the series of transactions described in Note 12 relate to entities under common control, these consolidated financial statements reflect the assets, liabilities, statements of operations and cash flows of us beginning November 7, 2012 and of our Predecessor as of and for the periods ending prior to November 7, 2012. Description of Business We are a master limited partnership 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 approximately 3,041 miles of pipeline. We are headquartered in Dallas, Texas. Segments Our chief operating decision-maker is our 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.

BASIS OF PRESENTATION

BASIS OF PRESENTATION	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
BASIS OF PRESENTATION	Basis of Presentation The accompanying consolidated financial statements and related notes present the consolidated balance sheets as of December 31, 2014 and 2013 and the consolidated statements of operations, comprehensive income (loss), cash flows and changes in partners' capital and members' equity for the years ended December 31, 2014, 2013 and 2012 (See Note 2). As a result of our IPO, there was no change in the accounting basis of the contributed net assets of Southcross Energy LLC. Information included in these financial statements and related notes are presented as if we and Southcross Energy LLC were the same entity, except with respect to associated changes in capitalization as described in Note 12. The consolidated financial statements reflect the assets acquired and liabilities assumed and the related operating results beginning on March 6, 2014 associated with the Onyx pipelines acquisition as discussed further in Note 3. The consolidated financial statements also reflect the TexStar Rich Gas System Transaction and the 2015 Holdings Acquisition and the related operating results beginning on August 4, 2014, as discussed further in Note 3. As a result of the Holdings Transaction, Holdings acquired a controlling equity interest in the Partnership, which was accounted for under the acquisition method of accounting in the consolidated financial statements of Holdings, whereby Holdings recorded the Partnership’s assets acquired and liabilities assumed at fair value. However, because less than 80% of the equity interests in the Partnership were acquired, push down accounting of Holdings’ basis in the Partnership was prohibited in our consolidated financial statements. Additionally, because the TexStar Rich Gas System was owned by TexStar, the Partnership recorded the TexStar Rich Gas System at TexStar’s historical cost. Thus, the difference between consideration paid and the TexStar Rich Gas System’s historical cost (net book value) at August 4, 2014, the date on which the Holdings Transaction and the TexStar Rich Gas System Transaction closed, was recorded as a reduction to partners’ capital. Management concluded that the Partnership was the predecessor for accounting purposes for periods prior to August 4, 2014. We recognized the 2015 Holdings Acquisition 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 3. The accompanying consolidated financial statements were prepared in accordance with accounting principles generally accepted in the U.S. ("GAAP") and in accordance with the rules and regulations of the U.S. Securities and Exchange Commission ("SEC"). Our consolidated financial statements include the accounts of Southcross and its 100% owned subsidiaries. We eliminate all intercompany balances and transactions in preparing consolidated financial statements. Principles of Consolidation We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. We do not have ownership in any consolidated variable interest entities. Use of Estimates The preparation of the consolidated financial statements in conformity with GAAP 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 consolidated financial statements and the reported amounts of revenues and expenses during the period. Actual results may differ from those estimates. Significant Accounting Policies Revenue Recognition Using the revenue recognition criteria of persuasive evidence of an exchange arrangement exists, delivery has occurred or services have been rendered and the price is fixed or determinable, we record natural gas and NGL revenue in the period when the physical product is delivered to the customer and in an amount based on the pricing terms of an executed contract. Our transportation, compression, processing, fractionation and other revenue is recognized in the period when the service is provided and includes our fee-based service revenue. In addition, collectability is evaluated on a customer-by-customer basis. New customers are subject to a credit review process, which evaluates the customers' financial position and their ability to pay. Our sale and purchase arrangements are primarily accounted for on a gross basis in the statements of operations. These transactions are contractual arrangements that establish the terms of the purchase of natural gas or NGLs at a specified location and the sale of natural gas or NGLs at a different location on the same or on another specified date. These transactions require physical delivery and transfer of the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk. We derive revenue in our business from the following types of arrangements: • Fixed-Fee. We receive a fixed-fee per unit of natural gas volume that we gather at the wellhead, process, treat, compress and/or transport for our customers, or we receive a fixed-fee per unit of NGL volume that we fractionate. Some of our arrangements also provide for a fixed-fee for guaranteed transportation capacity on our systems. • Fixed-Spread. Under these arrangements, we purchase natural gas and NGLs from producers or suppliers at receipt points on our systems at an index price plus or minus a fixed price differential and sell these volumes of natural gas and NGLs at delivery points off our systems at the same index price, plus or minus a fixed price differential. By entering into such back-to-back purchases and sales, we are able to mitigate our risk associated with changes in the general commodity price levels of natural gas and NGLs. We remain subject to variations in our fixed-spreads to the extent we are unable to precisely match volumes purchased and sold in a given time period or are unable to secure the supply or to produce or market the necessary volume of products at our anticipated differentials to the index price. • Commodity-Sensitive. In exchange for our processing services, we may remit to a customer a percentage of the proceeds from our sales, or a percentage of the physical volume, of residue natural gas and/or NGLs that result from our natural gas processing, or we may purchase NGLs from customers at set fixed NGL recoveries and retain the balance of the 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. Long-Lived Assets Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead and the cost of financing construction. Costs associated with obtaining rights of way agreements and easements to facilitate the building and maintenance of new pipelines are capitalized and depreciated over the life of the associated pipeline. We capitalize major units of property replacements or improvements and expense minor items. We use the straight-line method to depreciate property, plant and equipment over the estimated useful lives of the assets. We depreciate leasehold improvements and capital lease assets over the shorter of the life of the asset or the life of the lease. Maintenance and repairs are charged directly to expense. Our intangible assets consist of acquired long-term supply and gas gathering contracts. We amortize these contracts on a straight-line basis over the 30-year expected useful lives of the contracts. Impairment of Long-Lived Assets We evaluate our long-lived assets, which include finite-lived intangible assets, for impairment when events or circumstances indicate that their carrying values may not be recoverable. These events include, but are not limited to, market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, we evaluate the recoverability of our carrying value based on the long-lived asset's ability to generate future cash flows on an undiscounted basis. If the undiscounted cash flows are not sufficient to recover the long-lived asset's carrying value, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying values of the asset downward, if necessary, to their estimated fair value. Our fair value estimates are generally based on assumptions market participants would use, including market data obtained through the sales process or an analysis of expected discounted cash flows. With the recent decline in commodity prices negatively affecting the level of natural gas and crude oil production, we are more susceptible to potential impairment. During the year ended December 31, 2014, we recorded $1.6 million of impairment costs primarily related to right of way costs on a canceled project. We did not record any impairments during the years ended 2013 and 2012. 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): Year Ended December 31, 2014 2013 2012 Total interest costs $ 18,649 $ 14,047 $ 12,035 Capitalized interest included in property, plant and equipment, net (3,087 ) (1,457 ) (6,268 ) Interest expense $ 15,562 $ 12,590 $ 5,767 Cash and Cash Equivalents We consider all short-term investments with an original maturity of three months or less to be cash equivalents. At December 31, 2014 and 2013, except for amounts held in bank accounts to cover current payables, all of our cash equivalents were invested in short-term money market accounts and overnight sweep accounts. Allowance for Doubtful Accounts In evaluating the collectability of our accounts receivable, we perform credit evaluations of our new customers and adjust payment terms based upon payment history and each customer's current creditworthiness, as determined by our review of such customer's credit information. We extend credit on an unsecured basis to many of our customers. At December 31, 2014 and 2013, we have recorded no allowance for uncollectible accounts receivable. 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 other assets on the consolidated balance sheets. Changes in deferred financing costs are as follows (in thousands): Year Ended December 31, 2014 2013 Deferred financing costs, January 1 $ 5,237 $ 4,385 Capitalization of deferred financing costs (1) 15,659 2,139 Amortization of deferred financing costs (2) (4,192 ) (1,287 ) Deferred financing costs, December 31 $ 16,602 $ 5,237 ___________________________________________________________________________ (1) See Note 8. (2) This amount includes $2.3 million written off in connection with repayment of the Previous Credit Facility (as defined in Note 8) and contemporaneously entering into the Senior Credit Facilities (as defined in Note 8) in August 2014. Asset Retirement Obligations We evaluate whether any future asset retirement obligations ("AROs") exist and estimate the costs for such AROs for certain future events. An ARO will be recorded in the periods where we can reasonably determine the settlement dates or the period in which the expense is incurred and an estimated cost of the retirement obligation. Generally we do not have the intention of discontinuing the use of any significant assets or have a legal obligation to do so. Therefore, in these situations we do not have sufficient information to reasonably estimate any future AROs. However, during the year ended December 31, 2013, an asset retirement obligation of $0.5 million related to the discontinued use of an asset was recorded in operations and maintenance expense. This ARO is substantially complete and we do not expect significant additional costs. No AROs were recorded for the years ended December 31, 2014. Environmental Costs and Other Contingencies We recognize liabilities for environmental and other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and no specific amount in that range is more likely than any other, the low end of the range is accrued. No amounts were recorded as of December 31, 2014 and 2013. Fair Value of Financial Instruments Accounting guidance requires the disclosure of the fair value of all financial instruments that are not otherwise recorded at fair value in the financial statements. At December 31, 2014 and 2013, financial instruments recorded at contractual amounts that approximate fair value include certain funds on deposit, accounts receivable, other receivables and accounts payable and accrued liabilities. The fair values of such items are not materially sensitive to shifts in market interest rates because of the short term to maturity of these instruments (See Note 6). The fair value of the debt funded through our Credit Facility approximates its carrying amount as of December 31, 2014 and 2013 due primarily to the variable nature of the interest rate of the instrument and is considered a Level 2 fair value measurement (See Note 6). Derivative Instruments In our normal course of business, we enter into month-ahead commodity swap contracts in order to hedge economically our exposure to certain intra-month natural gas index pricing risk. We manage our interest rate risk through interest rate swaps and interest rate caps (See Note 6). Derivative financial instruments are recorded in the consolidated balance sheets at fair value, except for derivative contracts that we qualify for and for which we have elected the normal purchase or normal sale exceptions, which are not reflected in the consolidated balance sheets or statements of operations prior to accrual of the settlement. We present our derivative assets and liabilities on a net basis. If certain criteria are met, a derivative financial instrument may be designated as a fair value hedge or cash flow hedge. The changes in fair value of cash flow hedges are deferred in accumulated other comprehensive loss, net of tax, to the extent the contracts are, or have been, effective as hedges, until the forecasted transactions impact earnings. The ineffective portion of changes in fair value of cash flow hedges is recognized immediately into earnings. On an ongoing basis, a derivative instrument designated as a cash flow hedge must be highly effective in offsetting changes in cash flows of the hedged item. If it is determined that the derivative instrument is not highly effective as a hedge, hedge accounting will be discontinued prospectively. Changes in fair value of the associated hedging instrument are then recognized immediately in earnings for the remainder of the contract term unless a new hedging relationship is designated. The assessment of effectiveness excludes counterparty default risk and our own non-performance risk. The effect of these valuation adjustments was immaterial for the years ended December 31, 2014 and 2013. Derivative financial instruments designated as cash flow hedges must have a high correlation between price movements in the derivative and the hedged item. If and when an acceptable level of correlation no longer exists, hedge accounting ceases and changes in fair value are recognized in our statements of operations. If it becomes probable that a forecasted transaction will not occur, we immediately recognize the related deferred gains or losses in our statements of operations. Changes in fair value of the associated hedging instrument are then recognized immediately in earnings for the remainder of the contract term unless a new hedging relationship is designated. In March 2012, we entered into an interest rate swap to reduce the risks with respect to the variability of the interest rates under our Previous Credit Facility. In February 2014, we discontinued cash flow hedge accounting on a prospective basis as a result of the repayment of borrowings under our Previous Credit Facility (See Note 8). With the exception of these interest rate swaps, we did not have any other derivative financial instruments designated as fair value or cash flow hedges for accounting purposes during the years ended December 31, 2014 and 2013. For our derivative financial instruments that have not been designated as cash flow hedges for accounting purposes, changes in such instruments' fair values are recognized immediately in earnings. We do not hold or issue financial instruments or derivative financial instruments for trading purposes. Unit-Based Compensation Unit-based awards which settle in common units are classified as equity and are recognized in the financial statements over the vesting period at their grant date fair value. Unit-based awards which settle in cash are classified as liabilities and remeasured at every balance sheet date through settlement, such that the vested portion of the liability is adjusted to reflect its revised fair value through compensation expense. Currently, all awards granted under the long-term incentive plan will be settled in common units. Compensation expense associated with unit-based awards, adjusted for forfeitures, is recognized evenly from the date of the grant over the vesting period within general and administrative expenses on our consolidated statements of operations. Income Taxes No provision for federal or state income taxes, except as noted below, is included in our statements of operations as such income is taxable directly to our partners. Each partner is responsible for its share of federal and state income tax. Net earnings for financial statement purposes may differ significantly from taxable income reportable to each partner as a result of differences between the tax basis and financial reporting basis of assets and liabilities. We are subject to the Texas margin tax which qualifies as an income tax under GAAP that requires us to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis. Our current tax liability will be assessed based on the gross revenue apportioned to Texas. For the years ended December 31, 2014 and 2013, there were no material temporary differences. On September 13, 2013, the U.S. Department of the Treasury and IRS issued the final and re-proposed tangible property regulations effective for tax years beginning January 1, 2014. The provisions of these regulations had no impact our financial statements. Uncertain Tax Positions We evaluate the uncertainty in tax positions taken or expected to be taken in the course of preparing our consolidated financial statements to determine whether the tax positions are more likely than not of being sustained by the applicable tax authority. Tax positions deemed not to meet the more likely than not threshold would be recorded as a tax benefit or expense in the current year. We believe that there are no uncertain tax positions and that no provision for income tax is required for these consolidated financial statements. Earnings per Unit Net income (loss) per unit is calculated under the two-class method of computing earnings per unit when participating or multiple classes of securities exist. Under this method, undistributed earnings or losses for a period are allocated based on the contractual rights of each security to share in those earnings as if all of the earnings for the period had been distributed. Basic net income (loss) per unit excludes dilution and is computed by dividing net income (loss) attributable to limited partner common units by the weighted average number of limited partner common units outstanding during the period. Paid-in kind distributions and valuation adjustments to maximum redemption value of the Series A convertible preferred units (which converted to common units on August 4, 2014) are excluded from income available to common units in the calculation of basic earnings per unit. Dilutive net income (loss) per unit reflects potential dilution from the potential issuance of limited partner common units. Dilutive net income (loss) per unit is calculated using the treasury stock method. It is computed by dividing net income (loss) attributable to limited partner common units by the weighted average number of limited partner common units outstanding during the period increased by the number of additional limited partner common units that would have been outstanding if the dilutive potential limited partner common units had been issued. Investments in Joint Ventures We now hold equity interests in three joint venture entities as a result of the TexStar Rich Gas System Transaction. We own a 50% or less equity interest in each of the three entities. The joint venture arrangements give equal management rights with no single investor having unilateral control. Each party sharing joint control must consent to the ventures’ operating, investing and financing decisions. Therefore, because we do not have controlling financial interests, but do have significant influence, we use the equity method of accounting for investments in joint ventures. We recognize our share of the earnings and losses in the joint ventures pursuant to the terms of the applicable limited liability agreements governing such joint ventures, which provide for earnings and losses generally to be allocated based upon each member’s respective ownership interest in the joint ventures. We record our proportionate share of the joint ventures’ net income/loss as equity in income/losses of joint venture investments in the statements of operations. We evaluate investments in joint ventures for impairment when factors indicate that a decrease in the value of the investment has occurred that is not temporary. See Note 16. Recent Accounting Pronouncements Accounting standard-setting organizations frequently issue new or revised accounting rules. We review new pronouncements to determine their impact, if any, on our consolidated financial statements. We are evaluating the impact of each pronouncement on our consolidated financial statements. In 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 in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. We are required to adopt this standard beginning in the first quarter of 2017. In 2014, a new discontinued operations standard was issued that will update existing discontinued operations guidance. The standard will raise the threshold for disposals to qualify as discontinued operations. We are required to adopt this standard beginning in the first quarter of 2015. 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. We are required to adopt this standard beginning in the first quarter of 2017.

LIQUIDITY CONSIDERATIONS AND EQ

LIQUIDITY CONSIDERATIONS AND EQUITY OFFERINGS	12 Months Ended
	Dec. 31, 2014
Cash and Cash Equivalents [Abstract]
Liquidity Considerations and Equity Offerings	LIQUIDITY CONSIDERATIONS Our business exposes us to certain risks associated with the development of natural gas, crude oil and natural gas liquids which could have a material adverse effect on our cash flows, operations and liquidity, including, but not limited to: • fluctuations in the volume of natural gas we gather, process, treat, compress and transport and the volume of NGLs we fractionate and transport; • fluctuations in drilling and development activity in the geographic locations in which we operate; • credit risk associated with all customers; and • the level of production of, and the demand for, crude oil, natural gas and NGLs and the market prices of crude oil, natural gas and NGLs. Beginning in the second half of 2014 and continuing through the issuance of our financial statements, commodity prices have experienced increased volatility. In particular, crude oil and NGL prices have decreased significantly. If we experience a material reduction in drilling in the geographic areas in which we operate, including the Eagle Ford Shale, or significant, prolonged pricing deterioration of the commodities we sell, our future cash flow may be materially adversely affected. For the year ended December 31, 2014, the majority of our revenue was derived from fixed-fee contracts, which have limited direct exposure to commodity price levels since we are paid based on the volumes of natural gas that we gather, process, treat, compress and transport and the volumes of NGLs we fractionate and transport, rather than the value of the underlying natural gas or NGLs. A percentage of our contract portfolio contains minimum volume commitment arrangements. As a result of these contractual arrangements, the majority of our volumes associated with fixed-fee arrangements are dependent upon the level of drilling activity of producers. After considering these uncertainties and in developing our annual budget for 2015, our forecast indicates a potential shortfall in the amount of consolidated EBITDA (as defined in our Credit Facility (as defined in Note 8)) to comply with the consolidated total leverage ratio of our financial covenants in our Credit Facility. As discussed in further detail in Note 8, we have the right (which cannot be exercised more than two times in any twelve month period or more than four times during the term of the facility) to cure such a Financial Covenant Default (as defined in Note 8) by having our Sponsors or Holdings purchase equity interests in or make capital contributions (an equity cure) to us resulting in, among other things, proceeds that, if added to consolidated EBITDA, as defined in the Credit Facility, would result in us satisfying the Financial Covenants (as defined in Note 8). 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. Further, our Credit Facility does not place a dollar limit on the amount of an equity cure that can be contributed to comply with our Financial Covenants. Should there be an event of default under the Credit Facility, and such default is not cured, we would also experience a cross default under our Term Loan Agreement (defined in Note 8) and all of our debt would become due and payable to our lenders. In response to the Partnership’s expected need for additional liquidity, the controlling owners of Southcross Holdings GP LLC (the general partner of Holdings, which controls our General Partner) have committed to provide the necessary funding to support the Partnership for at least a reasonable period of time in an amount up to $25 million to ensure the Partnership has sufficient liquidity to comply with its applicable Financial Covenants, normal operating and growth capital requirements. Therefore, our financial statements have been presented as if the Partnership will continue as a going concern. See Note 8.

ACQUISITIONS

ACQUISITIONS	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Business Combinations [Abstract]
ACQUISITIONS	ACQUISITIONS TexStar Rich Gas System Transaction. On August 4, 2014, contemporaneously with the closing of the Holdings Transaction, TexStar contributed to us the TexStar Rich Gas System through a contribution of TexStar’s equity interest in the entities that own the TexStar Rich Gas System (the “Contribution”). In exchange for the Contribution, we paid $80 million in cash, assumed $100 million of debt (which was immediately repaid through our Term Loan Agreement (as defined in Note 6)) and issued 14,633,000 Class B Convertible Units (the “Class B Convertible Units”). The TexStar Rich Gas System consists of a cryogenic processing plant, located in Bee County, Texas, and joint venture ownership in natural gas gathering and residue pipelines across the core producing areas extending from Dimmit to Karnes Counties, Texas in the liquids-rich window of the Eagle Ford Shale region. These pipelines are operated under split-capacity arrangements within joint venture arrangements with Targa Pipeline Partners LP (see Note 13). The amount of the consideration paid over TexStar’s net book value of the assets received and liabilities assumed of the TexStar Rich Gas System was recorded as a reduction to partners’ capital as summarized as follows (in thousands): Consideration paid (1) $ 404,414 Current assets $ 1,295 Property, plant and equipment, net 255,220 Investments in joint ventures (2) 152,050 Total assets contributed 408,565 Total liabilities assumed (3) (102,776 ) Net identifiable assets contributed $ 305,789 Consideration paid in excess of net assets contributed $ 98,625 Allocation of reduction to partners' capital: Common limited partner interest $ 45,420 Class B Convertible limited partner interest 27,925 Subordinated limited partner interest 23,308 General Partner interest 1,972 Total reduction to partners' capital $ 98,625 (1) This amount was calculated as follows: $80 million of cash plus 14,633,000 Class B Convertible Units at an issue price of $22.17 , the closing price of the Partnership’s common units on August 4, 2014. (2) Significant assets acquired through the TexStar Rich Gas System Transaction include equity interests in three joint ventures. See Note 13. (3) This amount includes $100 million of debt assumed. Onyx Pipelines Acquisition. On March 6, 2014, our subsidiary, Southcross Nueces Pipelines LLC, acquired natural gas pipelines near Corpus Christi, Texas and contracts related to these pipelines from Onyx Midstream, LP and Onyx Pipeline Company (collectively, “Onyx”) for $38.6 million in cash, net of certain adjustments as provided in the purchase agreement. The pipelines transport natural gas to two power plants in Nueces County, Texas under fixed-fee contracts that extend through 2029 and include an option to extend the agreements by an additional term of up to ten years. The contracts were renegotiated in connection with the acquisition; therefore, we considered these contracts to be assumed at fair market value. The fair values of the property, plant and equipment were based upon assumptions related to expected future cash flows, discount rates and asset lives using currently available information. We utilized a mix of the cost, income and market approaches to determine the estimated fair values of such assets. The fair value measurements and models were classified as non-recurring Level 3 measurements. We performed our assessment of the fair value of the assets acquired and liabilities assumed, and the consideration given was considered equal to the fair value of net assets acquired. As a result, no goodwill was recorded. The assessment was finalized during the second quarter of 2014 and there were no subsequent changes to the preliminary balances recorded. The fair value of the assets acquired and liabilities assumed related to the Onyx purchase price was as follows (in thousands): Purchase Price—Cash $ 38,636 Current assets $ 730 Property, plant and equipment 39,413 Total assets acquired 40,143 Current liabilities assumed (1,407 ) Other liabilities assumed (100 ) Net identifiable assets acquired $ 38,636 Unaudited Pro Forma Financial Information for Onyx Pipelines Acquisition. The following unaudited pro forma financial information for the three months ended March 31, 2014 assumes that the acquisition of pipelines from Onyx occurred on January 1, 2013 and includes adjustments for income from operations, including depreciation and amortization, as well as the effects of financing the transaction (in thousands, except unit information): Three Months Ended March 31, 2014 Total revenue $ 214,240 Net loss (1,397 ) Net loss attributable to common unitholders (1,115 ) Net loss per common unit (basic and diluted) (0.06 ) Net loss attributable to subordinated unitholders (745 ) Net loss per subordinated unit (basic and diluted) (0.06 ) The unaudited pro forma information is not necessarily indicative of what our statements of operations would have been if the transaction had occurred on that date, or what the financial position or results from operations will be for any future periods. For the period from March 6, 2014 through March 31, 2014, the Onyx pipelines business contributed $0.3 million in revenues and $0.1 million in net income to our statements of operations. Texoz Acquisition. On November 21, 2014, we completed the acquisition of a natural gas gathering system in McMullen County, Texas (the “Texoz System”) from LT Gathering, LLC for $5.4 million in cash, net of certain adjustments as provided in the purchase agreement (the “Texoz Acquisition”). The Texoz System consists of eight miles of gathering pipelines within two miles of our existing rich gas pipeline network and services customers under acreage dedication contracts. Due to the immaterial amount of this transaction, no pro-forma financial information has been presented. Holdings Drop-Down Acquisition. On May 7, 2015, we completed the 2015 Holdings Acquisition 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. The acquired assets consist of the Valley Wells System, the Compression Assets and two NGL pipelines that were under construction at the time of the transaction (and that are now operational). Total consideration for the assets was $15.0 million in cash and 4.5 million new common units, valued as of the date of closing, issued to Holdings equating to $77.6 million . We also assumed the remaining capital expenditures for the completion of the NGL pipelines that were under construction. The Valley Wells System is located in the Eagle Ford Shale region, in La Salle County, Texas. The system has sour gas treating capacity of approximately 100 MMcf/d and is supported by a 35 MMcf/d minimum volume commitment. The system is connected to our rich gas system for transport and processing. The assets acquired in the 2015 Holdings Acquisition include over 50,000 horsepower of compression capability that serve both the Valley Wells and Lancaster gathering systems located primarily in Dimmit, Frio and LaSalle counties. The NGL pipelines, which were completed in June 2015, include a Y-grade pipeline that connects our Woodsboro processing facility to Holdings’ Robstown fractionator (“Robstown”) and a propane pipeline from our Bonnie View fractionator to Robstown. Because of the common control aspects in the 2015 Holdings Acquisition, 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. The acquired NGL pipelines were accounted for as an asset acquisition and will be included in the historical financial statements, and before May 7, 2015. The consolidated net assets associated with the Valley Wells System and Compression Assets as of March 31, 2015 were $88.8 million and are presented in the consolidated balance sheet of the Partnership. As a carve-out transaction, the 2015 Holdings Acquisition has no cash accounts. As such, accounts receivable and accounts payable, along with certain other assets and liabilities that would be settled in cash, were the rights and obligations of Holdings as of March 31, 2015. 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. Pooling of Interests. As noted above, the 2015 Holdings Acquisition was between commonly controlled entities which required that we account for the acquisitions in a manner similar to a pooling of interests. As a result, the historical financial statements of the Partnership and the Valley Wells System and Compression Assets have been combined to reflect the historical operations, financial position and cash flows from the date common control began on August 4, 2014. Revenues and net income for the previously separate entities and the combined amounts for the three months ended March 31, 2015, are as follows (in thousands): Three Months Ended March 31, 2015 Partnership revenues $ 180,549 Valley Wells System and Compression Assets revenue (1) 5,389 Combined revenues $ 185,938 Partnership net income $ (10,751 ) Valley Wells System and Compression Assets net loss (1) (3,154 ) Combined net income $ (13,905 ) (1) Results are fully reflected in the Partnership's results of operations for the three months ended March 31, 2015.	ACQUISITIONS TexStar Rich Gas System Transaction. On August 4, 2014, contemporaneously with the closing of the Holdings Transaction, TexStar contributed to us certain gathering and processing assets (the “TexStar Rich Gas System”), through a contribution of TexStar’s equity interest in the entities that own the TexStar Rich Gas System (the “Contribution”) to us. In exchange for the Contribution, we paid $80 million in cash, assumed $100 million of debt (which was immediately repaid through our Term Loan Agreement (as defined in Note 8)) and issued 14,633,000 Class B Convertible Units (the “Class B Convertible Units”). The TexStar Rich Gas System consists of a cryogenic processing plant, located in Bee County, Texas, and joint venture ownership in natural gas gathering and residue pipelines across the core producing areas extending from Dimmit to Karnes Counties, Texas in the liquids-rich window of the Eagle Ford Shale region. These pipelines are operated under split-capacity arrangements within joint venture arrangements with Atlas Pipeline Partners, L.P. The amount of the consideration paid over TexStar’s net book value of the assets received and liabilities assumed of the TexStar Rich Gas System is recorded as a reduction to partners’ capital as summarized as follows (in thousands): Consideration paid (1) $ 404,414 Current assets $ 1,295 Property, plant and equipment, net 255,220 Investments in joint ventures (2) 152,050 Total assets contributed 408,565 Total liabilities assumed (3) (102,776 ) Net identifiable assets contributed $ 305,789 Consideration paid in excess of net assets contributed $ 98,625 Allocation of reduction to partners' capital: Common limited partner interest $ 45,420 Class B Convertible limited partner interest 27,925 Subordinated limited partner interest 23,308 General Partner interest 1,972 Total reduction to partners' capital $ 98,625 ____________________________________________________________________________ (1) This amount was calculated as follows: $80 million of cash plus 14,633,000 Class B Convertible Units at an issue price of $22.17 , the closing price of the Partnership’s common units on August 4, 2014. (2) Significant assets acquired through the TexStar Rich Gas System Transaction include equity interests in three joint ventures. See Note 16. (3) This amount includes $100 million of debt assumed. Onyx Pipelines Acquisition. On March 6, 2014, our subsidiary, Southcross Nueces Pipelines LLC, acquired natural gas pipelines near Corpus Christi, Texas and contracts related to these pipelines from Onyx Midstream, LP and Onyx Pipeline Company (collectively, “Onyx”) for $38.6 million in cash, net of certain adjustments as provided in the purchase agreement. The pipelines transport natural gas to two power plants in Nueces County, Texas under fixed-fee contracts that extend through 2029 and include an option to extend the agreements by an additional term of up to ten years. The contracts were renegotiated in connection with the acquisition; therefore, we consider these contracts to be assumed at fair market value. The fair values of the property, plant and equipment are based upon assumptions related to expected future cash flows, discount rates and asset lives using currently available information. We utilized a mix of the cost, income and market approaches to determine the estimated fair values of such assets. The fair value measurements and models have been classified as non-recurring Level 3 measurements. We performed our assessment of the fair value of the assets acquired and liabilities assumed, and the consideration given was considered equal to the fair value of net assets acquired. As a result, no goodwill was recorded. The assessment was finalized during the second quarter of 2014 and there were no changes to the preliminary balances previously recorded. The fair value of the assets acquired and liabilities assumed related to the Onyx purchase price was as follows (in thousands): Purchase Price—Cash $ 38,636 Current assets $ 730 Property, plant and equipment 39,413 Total assets acquired 40,143 Current liabilities assumed (1,407 ) Other liabilities assumed (100 ) Net identifiable assets acquired $ 38,636 Unaudited Pro Forma Financial Information for Onyx Pipelines Acquisition. The following unaudited pro forma financial information for the year ended December 31, 2013 and the year ended December 31, 2014 assumes that the acquisition of pipelines from Onyx occurred on January 1, 2013 and includes adjustments for income from operations, including depreciation and amortization, as well as the effects of financing the transaction (in thousands, except unit information): Year Ended December 31, 2014 2013 Total revenue $ 843,376 $ 639,104 Net loss (31,400 ) (18,306 ) Net loss attributable to common unitholders (20,211 ) (9,934 ) Net loss per common unit (basic and diluted) (0.85 ) (0.68 ) Net loss attributable to subordinated unitholders (8,373 ) (9,678 ) Net loss per subordinated unit (basic and diluted) (0.69 ) (0.79 ) The unaudited pro forma information is not necessarily indicative of what our statements of operations would have been if the transaction had occurred on that date, or what the financial position or results from operations will be for any future periods. For the year ended December 31, 2014, the Onyx pipelines business contributed $4.2 million in revenues and $1.3 million in net income to our statements of operations. Texoz Acquisition. On November 21, 2014, we completed the acquisition of a natural gas gathering system in McMullen County, Texas (the “Texoz System”) from LT Gathering, LLC for $5.4 million in cash, net of certain adjustments as provided in the purchase agreement (the “Texoz Acquisition”). The Texoz System consists of eight miles of gathering pipelines within two miles of our existing rich gas pipeline network and services customers under acreage dedication contracts. Due to the immaterial amount of this transaction, no pro-forma financial information was disclosed in this report. Holdings Drop-Down Acquisition. On May 7, 2015, we completed the 2015 Holdings Acquisition 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. The acquired assets consist of the Valley Wells System, Compression Assets and two NGL pipelines that were under construction at the time of the transaction (and that are now operational). Total consideration for the assets was $15.0 million in cash and 4.5 million new common units, valued as of the date of closing, issued to Holdings equating to $77.6 million . We also assumed the remaining capital expenditures for the completion of the NGL pipelines that were under construction. The Valley Wells System is located in the Eagle Ford Shale region, in La Salle County, Texas. The system has sour gas treating capacity of approximately 100 MMcf/d and is supported by a 35 MMcf/d minimum volume commitment. The system is connected to our rich gas system for transport and processing. The assets acquired in the 2015 Holdings Acquisition include over 50,000 horsepower of compression capability that serve both the Valley Wells and Lancaster gathering systems located primarily in Dimmit, Frio and LaSalle counties. The NGL pipelines, which were completed in June 2015, include a Y-grade pipeline that connects our Woodsboro processing facility to Holdings’ Robstown fractionator (“Robstown”) and a propane pipeline from our Bonnie View fractionator to Robstown. Because of the common control aspects in the 2015 Holdings Acquisition, 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 consolidated net assets associated with the Valley Wells System and Compression Assets as of December 31, 2014 were $77.3 million and are presented in the consolidated balance sheet of the Partnership. The acquired NGL pipelines were accounted for as an asset acquisition and will be included in the historical financial statements beginning on May 7, 2015. As a carve-out transaction, the 2015 Holdings Acquisition has no cash accounts. As such, accounts receivable and accounts payable, along with certain other assets and liabilities that would be settled in cash, were the rights and obligations of Holdings as of December 31, 2014. Given their nature and the fact that carve-out financial statements are meant to represent an entity’s operations as if it had existed as of the time common control occurred, we have presented these amounts as third-party receivables and payables. Pooling of Interests. 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 year ended December 31, 2014, are as follows (in thousands): Year Ended December 31, 2014 Partnership revenues $ 842,728 Valley Wells System and Compression Assets revenue (1) 5,785 Combined revenues $ 848,513 Partnership net loss $ (31,322 ) Valley Wells System and Compression Assets net loss (1) (6,409 ) Combined net loss $ (37,731 ) _________________________________ (1) Results are fully reflected in the Partnership's results of operations for the year ended December 31, 2014. TRANSACTION-RELATED COSTS During the year ended December 31, 2014, we recognized $9.9 million of transaction-related costs in connection with the Onyx acquisition, the Holdings Transaction, the TexStar Rich Gas System Transaction and the Texoz Acquisition, which are recorded in operations and maintenance and general and administrative expenses. For the year ended December 31, 2014, these costs include (a) $7.2 million related to the accelerated vesting of the LTIP awards (as defined in Note 5) due to the change in control as further discussed in Note 14, (b) $1.7 million of advisory, audit and legal fees, (c) $0.6 million of charges associated with employees’ severance, (d) $0.3 million related to professional fees associated with the Onyx acquisition and the Texoz Acquisition and (e) $0.1 million related to the accelerated vesting of the Southcross Energy LLC equity equivalent units due to the change in control as further discussed in Note 14. We expect to incur additional costs relating to integration and other activities throughout 2015.

EARNINGS PER LIMITED PARTNER UN

EARNINGS PER LIMITED PARTNER UNIT AND DISTRIBUTIONS	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Earnings Per Share [Abstract]
EARNINGS PER LIMITED PARTNER UNIT AND DISTRIBUTIONS	NET INCOME/LOSS PER LIMITED PARTNER UNIT AND DISTRIBUTIONS Net Income/Loss Per Limited Partner Unit The following is a reconciliation of the net loss attributable to our limited partners and our limited partner units and the basic and diluted earnings per unit calculations for the three months ended March 31, 2015 and 2014 (in thousands, except unit and per unit data): Three Months Ended March 31, 2015 2014 Net loss $ (13,905 ) $ (1,289 ) Series A Preferred Unit fair value adjustment (1) — 33 Series A Preferred Unit in-kind distribution — (534 ) General partner Unit in-kind distribution (76 ) — Net loss attributable to Holdings (3,154 ) — Net loss attributable to partners $ (10,827 ) $ (1,790 ) General partner's interest (2) (239 ) (26 ) Class B Convertible limited partner interest (2) (3,119 ) — Limited partners' interest (2) Common (4,936 ) (1,045 ) Subordinated (2,533 ) (719 ) (1) The valuation adjustment to maximum redemption value of the Series A Preferred Unit in-kind distribution decreased the net loss attributable to partners for the three months ended March 31, 2014. (2) General Partner's and limited partners’ interests are calculated based on the allocation of net losses for the period, net of the allocation of Series A Preferred Unit in-kind distributions, Series A Preferred Unit fair value adjustments and General Partner unit in-kind distributions. The Class B Convertible Unit interest is calculated based on the allocation of only net losses for the period. Three Months Ended March 31, Common Units 2015 2014 Interest in net loss $ (4,936 ) $ (1,045 ) Effect of dilutive units - numerator (1) — — Dilutive interest in net loss $ (4,936 ) $ (1,045 ) Weighted-average units - basic 23,800,943 18,285,220 Effect of dilutive units - denominator (1) — — Weighted-average units - dilutive 23,800,943 18,285,220 Basic and diluted net loss per common unit $ (0.21 ) $ (0.06 ) Three Months Ended March 31, Subordinated Units 2015 2014 Interest in net loss $ (2,533 ) $ (719 ) Effect of dilutive units - numerator (1) — — Dilutive interest in net loss $ (2,533 ) $ (719 ) Weighted-average units - basic 12,213,713 12,213,713 Effect of dilutive units - denominator (1) — — Weighted-average units - dilutive 12,213,713 12,213,713 Basic and diluted net loss per subordinated unit $ (0.21 ) $ (0.06 ) (1) Because we had a net loss for all periods for common units and the subordinated units, the effect of the dilutive units would be anti-dilutive to the per unit calculation. Therefore, the weighted average units outstanding are the same for basic and dilutive net loss per unit for those periods. The weighted average units that were not included in the computation of diluted per unit amounts were 2,081 and 140,100 for the three months ended March 31, 2015 and 2014, 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. All of our Series A Preferred Units were converted into common units on August 4, 2014 (see Note 8). Prior to conversion, our Series A Preferred Units were considered participating securities for purposes of the basic earnings per unit calculation during periods in which they received cash distributions. We were required to pay in-kind distributions to the Series A Preferred Units for the first four full quarters beginning the second quarter of 2013, and continued to pay these distributions until the Series A Preferred Units were converted into common units. Because the Series A Preferred Units received in-kind distributions, they have been excluded from the basic earnings per unit calculation for the three months ended March 31, 2014. Distributions Our agreement of limited partnership, which was amended and restated on August 4, 2014 in order to establish the Class B Convertible Units (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. We intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $0.40 per unit, or $1.60 on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our General Partner. However, 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 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. With respect to the fourth quarter of 2014, Holdings also waived the requirement that any distribution owed to it for that quarter be paid within 45 days of the end of the quarter, provided that the distribution was paid before or in conjunction with the filing of our 2014 Annual Report on Form 10-K. We paid a distribution of $0.28 per unit on our 12,213,713 subordinated units in conjunction with the filing of our 2014 Annual Report on Form 10-K. Paid In-Kind Distributions Series A Preferred Units. During the second quarter of 2013, we raised $40.0 million of equity through issuances of 1,715,000 Series A Preferred Units and an additional General Partner contribution to satisfy the requirements of our Previous Credit Facility (as defined in Note 6) (see Notes 6 and 8). Under the terms of our Partnership Agreement, we were required to pay the holders of our Series A Preferred Units quarterly distributions of in-kind Series A Preferred Units for the first four full quarters following the issuance of the units and continuing thereafter until the board of directors of our General Partner determined to begin paying quarterly distributions in cash. In-kind distributions were in the form of Series A Preferred Units at a rate of $0.40 per outstanding Series A Preferred Unit per quarter (or 7% per year of the per unit purchase price). Cash distributions were required to equal the greater of $0.40 per unit per quarter or the quarterly distribution paid with respect to each common unit. In accordance with the Partnership Agreement, our General Partner received a corresponding distribution of in-kind general partner units to maintain its 2.0% interest in us. In connection with the Holdings Transaction (see Notes 1 and 2), all holders of the Series A Preferred Units elected to convert their Series A Preferred Units into 2,015,638 common units based on a 110% exchange ratio. The following table represents the paid in-kind (“PIK”) distribution declared in 2014 through August 4, 2014, the date on which all outstanding Series A Preferred Units were converted to common units (in thousands, except per unit and in-kind distribution units): Payment Date Attributable to the Quarter Ended (1) Per Unit Distribution In-Kind Series A In-Kind Series A Distributions (2) In-Kind Unit to General Partner In-Kind General Partner Distribution Value (2) 2014 May 15, 2014 March 31, 2014 $ 0.40 31,513 $ 534 643 $ 11 (1) As a result of the conversion, the Series A Preferred Unit holders (and the corresponding General Partner units) ceased receiving PIK distributions effective with the quarter ended June 30, 2014, but received a cash distribution on the converted common units. (2) 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. Class B Convertible Units. In connection with the Contribution and the TexStar Rich Gas System Transaction, on August 4, 2014, we established our Class B Convertible Units. As of March 31, 2015, the Class B Convertible Units consist of 15,149,636 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 14,633,000 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 9. The following table presents the PIK distribution earned on the Class B Convertible Units for periods after issuance on August 4, 2014 through March 31, 2015 (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 In-Kind Class B Convertible Distributions (1) In-Kind Unit to General Partner In-Kind General Partner Distribution Value (1) 2015 May 14, 2015 March 31, 2015 $ 0.3257 265,118 $ 3,712 5,410 $ 76 2014 February 13, 2015 December 31, 2014 $ 0.3257 260,558 $ 4,143 5,318 $ 85 November 14, 2014 September 30, 2014 $ 0.3257 256,078 $ 5,467 5,226 $ 112 (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. Cash Distributions The following table represents our distributions declared for the quarterly periods beginning in 2014 through the three months ended March 31, 2015 (in thousands, except per unit data): Distributions Attributable to the Per Unit Limited Partners Payment Date Quarter Ended Distribution Common Subordinated General Partner Total 2015 May 14, 2015 March 31, 2015 $ 0.40 $ 9,520 $ — $ 418 $ 9,938 2014 February 13, 2015 December 31, 2014 0.40 (1) 9,520 3,432 (2) 416 13,368 November 14, 2014 September 30, 2014 0.40 (1) 9,520 — 413 9,933 August 14, 2014 June 30, 2014 0.40 9,399 4,886 290 14,575 May 15, 2014 March 31, 2014 0.40 8,586 4,886 290 13,762 (1) The common unit distribution in the table above includes the distribution payment to the Series A Preferred unitholders for their Series A Preferred Units converted into common units or to the units that vested as part of our LTIP (as defined in Note 11) as a result of the Holdings Transaction (see Notes 1, 8 and 11). (2) Holdings waived the requirement that any distribution owed to it for the fourth quarter be paid within 45 days of the end of the quarter. We paid a distribution of $0.28 per unit on our 12,213,713 subordinated units in conjunction with the filing of our 2014 Annual Report on Form 10-K.	EARNINGS PER LIMITED PARTNER UNIT AND DISTRIBUTIONS Earnings Per Unit of the Partnership The following is a reconciliation of net loss attributable to limited partners and the limited partner units used in the basic and diluted earnings per unit calculations for the years ended December 31, 2014, 2013 and 2012 (in thousands, except per unit data): Year Ended December 31, 2014 (1) Year Ended December 31, 2013 Year Ended December 31, 2012 Net loss $ (37,731 ) $ (15,970 ) $ (4,488 ) Series A Preferred Unit fair value adjustment (2) (4,596 ) (37 ) — Series A Preferred Unit in-kind distribution (534 ) (1,633 ) — General partner Unit in-kind distribution (207 ) — — Net loss from January 1, 2012 through November 6, 2012 — — 260 Net loss attributable to Holdings (6,409 ) — — Net loss attributable to partners $ (36,659 ) $ (17,640 ) $ (4,228 ) General partner's interest (3) (693 ) (319 ) — Limited partners' Class B Convertible interest (3) (7,436 ) — — Limited partners' interest (2) Common (20,175 ) (8,683 ) (2,072 ) Subordinated (8,355 ) (8,638 ) (2,071 ) ____________________________________________________________________________ ( 1) We calculate historical earnings per unit with retrospective earnings or losses of a transferred business before the date of the 2015 Holdings acquisition allocated entirely to the General Partner. The previously reported earnings per unit of the limited partners did not change as a result of the 2015 Holdings acquisition. (2) The valuation adjustment to maximum redemption value of the Series A Preferred Unit in-kind distribution increased the net loss attributable to partners for the years ended December 31, 2014 and 2013 in the calculation of earnings per unit (See Note 11) . (3) G eneral Partner's and limited partners’ interests are calculated based on the allocation of net losses for the period, net of the allocation of Series A Preferred Unit in-kind distributions, Series A Preferred Unit fair value adjustments and General Partner unit in-kind distributions. The Class B Convertible Unit interest is calculated based on the allocation of only net losses for the period. Common Units Year Ended December 31, 2014 Year Ended December 31, 2013 Year Ended December 31, 2012 Interest in net loss $ (20,175 ) $ (8,683 ) $ (2,072 ) Effect of dilutive units - numerator (1) — — — Dilutive interest in net loss $ (20,175 ) $ (8,683 ) $ (2,072 ) Weighted-average units - basic 21,641,635 12,224,997 12,213,713 Effect of dilutive units - denominator (1) — — — Weighted-average units - dilutive 21,641,635 12,224,997 12,213,713 Basic and diluted net loss per common unit $ (0.93 ) $ (0.71 ) $ (0.17 ) Subordinated Units Year Ended December 31, 2014 Year Ended December 31, 2013 Year Ended December 31, 2012 Interest in net loss $ (8,355 ) $ (8,638 ) $ (2,071 ) Effect of dilutive units - numerator (1) — — — Dilutive interest in net loss $ (8,355 ) $ (8,638 ) $ (2,071 ) Weighted-average units - basic 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 Basic and diluted net loss per subordinated unit $ (0.68 ) $ (0.71 ) $ (0.17 ) ____________________________________________________________________________ (1) Because we had a net loss for all periods for common units and the subordinated units, the effect of the dilutive units would be anti-dilutive to the per unit calculation. Therefore, the weighted average units outstanding are the same for basic and dilutive net loss per unit for those periods. The weighted average units that were not included in the computation of diluted per unit amounts were 184,417 and 10,092 and unvested awards granted under our LTIP for the year ended December 31, 2014 and 2013, respectively, and 1,213,257 Series A Preferred Units for the year ended December 31, 2013. 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. All of our Series A Preferred Units were converted into common units on August 4, 2014 (See Note 11). Prior to conversion, our Series A Preferred Units were considered participating securities for purposes of the basic earnings per unit calculation during periods in which they received cash distributions. We were required to pay in-kind distributions to the Series A Preferred Units for the first four full quarters beginning the second quarter of 2013, and continued to pay these distributions until the Series A Preferred Units were converted into common units. Because the Series A Preferred Units received in-kind distributions, they have been excluded from the basic earnings per unit calculation for the year ended December 31, 2014. Distributions Our agreement of limited partnership, which was amended and restated on August 4, 2014 in order to establish the Class B Convertible Units (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. We intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $0.40 per unit, or $1.60 on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our General Partner. However, 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 holder of all of our 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 . With respect to the fourth quarter of 2014, Holdings also waived the requirement that any distribution owed to it for that quarter be paid within 45 days of the end of the quarter, provided that the distribution is paid before or in conjunction with the filing of this Form 10-K. Our General Partner is currently entitled to 2.0% of all distributions that we make prior to our liquidation. Our General Partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. Our General Partner's initial 2.0% interest in our distributions will be reduced if we issue additional limited partner units in the future and our General Partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest. Our General Partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50% , of the cash we distribute from operating surplus in excess of $0.46 per unit per quarter. The maximum distribution of 50% includes distributions paid to our General Partner on its 2.0% general partner interest and assumes that our General Partner maintains its general partner interest at 2.0% . The maximum distribution of 50% does not include any distributions that our General Partner may receive on any limited partner units that it owns. Cash Distributions The following table represents our distribution declared for the quarter ended December 31, 2014 and distributions paid for the previous periods (in thousands, except per unit data): Distributions Attributable to the Per Unit Limited Partners Payment Date Quarter Ended Distribution Common Subordinated General Partner Total 2014 February 13, 2015 December 31, 2014 $ 0.40 (1) $ 9,520 $ 3,432 (3) $ 416 $ 13,368 November 14, 2014 September 30, 2014 0.40 (1) 9,520 — 413 9,933 August 14, 2014 June 30, 2014 0.40 9,399 4,886 290 14,575 May 15, 2014 March 31, 2014 0.40 8,586 4,886 290 13,762 2013 February 14, 2014 December 31, 2013 0.40 8,581 4,885 289 13,755 November 14, 2013 September 30, 2013 0.40 4,888 4,885 214 9,987 August 14, 2013 June 30, 2013 0.40 4,890 4,886 210 9,986 May 15, 2013 March 31, 2013 0.40 4,888 4,886 199 9,973 2012 February 14, 2013 December 31, 2012 0.24 (2) 2,931 2,931 120 5,982 ____________________________________________________________________________ (1) The common unit distribution in the table above includes the distribution payment to the Series A Preferred unitholders for their Series A Preferred Units converted into common units or to the units that vested as part of our LTIP (as defined below) as a result of the Holdings Transaction (See Notes 1, 11 and 14). (2) Per unit distribution of $0.24 corresponds to the minimum quarterly distribution of $0.40 per unit, or $1.60 on an annualized basis, pro-rated for the portion of the quarter following the closing of our IPO on November 7, 2012. (3) Holdings waived the requirement that any distribution owed to it for the fourth quarter be paid within 45 days of the end of the quarter. We expect to pay a distribution of $0.28 on 12,213,713 of our Subordinated Units in conjunction with the filing of this Form 10-K. In accordance with our 2012 long-term incentive plan ("LTIP"), we paid the distribution equivalent rights to holders of LTIP units that vested during year ended December 31, 2014 (See Note 14). On November 14, 2013, we paid an aggregate distribution of $63.8 thousand to the holders of the vested phantom units. Paid In-Kind Distributions During the second quarter of 2013, we raised $40.0 million of equity through issuances of 1,715,000 Series A Preferred Units and an additional General Partner contribution to satisfy the requirements of our Previous Credit Facility (as defined in Note 8) (See Notes 8 and 11). Under the terms of our Partnership Agreement, we were required to pay the holders of our Series A Preferred Units quarterly distributions of in-kind Series A Preferred Units for the first four full quarters following the issuance of the units and continuing thereafter until the board of directors of our General Partner determined to begin paying quarterly distributions in cash. In-kind distributions were in the form of Series A Preferred Units at a rate of $0.40 per outstanding Series A Preferred Unit per quarter (or 7% per year of the per unit purchase price). Cash distributions were required to equal the greater of $0.40 per unit per quarter or the quarterly distribution paid with respect to each common unit. In accordance with the Partnership Agreement, our General Partner received a corresponding distribution of in-kind general partner units to maintain its 2.0% interest in us. In connection with the Holdings Transaction (see Notes 1 and 3), all holders of the Series A Preferred Units elected to convert their Series A Preferred Units into 2,015,638 common units based on a 110% exchange ratio. The following table represents the paid in-kind (“PIK”) distribution from the date of our IPO through August 4, 2014, the date on which all outstanding Series A Preferred Units were converted to common units (in thousands, except per unit and in-kind distribution units): Payment Date Attributable to the Quarter Ended (1) Per Unit Distribution In-Kind Series A Holders In-Kind Series A Distributions (2) In-Kind Unit to General Partner In-Kind General Partner Distribution Value (2) 2014 May 15, 2014 March 31, 2014 $ 0.40 31,513 $ 534 643 $ 11 2013 February 14, 2014 December 31, 2013 $ 0.40 30,971 $ 558 632 $ 11 November 14, 2013 September 30, 2013 0.40 30,439 511 621 10 August 14, 2013 June 30, 2013 0.35 (3) 22,276 512 454 10 August 14, 2013 June 30, 2013 0.20 (4) 2,199 51 45 1 ____________________________________________________________________________ (1) As a result of the conversion, the Series A Preferred Unit holders (and the corresponding General Partner units) did not receive a PIK distribution for the quarters ended June 30, 2014 or September 30, 2014, but received a cash distribution on the converted common units. (2) The fair value was calculated as required, based on the common unit price at the quarter end date for the period attributable to the distribution, multiplied by the number of units distributed. (3) Per unit distribution of $0.35 corresponds to the minimum quarterly distribution of $0.40 per unit, or $1.60 on an annualized basis, pro-rated for the portion of the quarter following the issuance of 1,466,325 Series A Preferred Units and 29,925 general partner units on April 12, 2013. (4) Per unit distribution of $0.20 corresponds to the minimum quarterly distribution of $0.40 per unit, or $1.60 on an annualized basis, pro-rated for the portion of the quarter following the issuance of 248,675 Series A Preferred Units and 5,075 general partner units on May 15, 2013. Class B Convertible Units. In connection with the Contribution, on August 4, 2014, we established our Class B Convertible Units. The Class B Convertible Units consist of 14,633,000 of such units plus any 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 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 12. The following table represents the PIK distribution earned on the Class B Convertible Units for periods after August 4, 2014 and ended December 31, 2014 (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 In-Kind Class B Convertible Distributions (1) In-Kind Unit to General Partner In-Kind General Partner Distribution Value (1) 2014 February 13, 2015 December 31, 2014 $ 0.3257 260,558 $ 4,143 5,318 $ 85 November 14, 2014 September 30, 2014 $ 0.3257 256,078 $ 5,467 5,226 $ 112 ____________________________________________________________________________ (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. Earnings Per Common Unit of Southcross Energy LLC A reconciliation of basic and diluted earnings per unit related to the Southcross Energy LLC common units is included in our consolidated statements of operations. Southcross Energy LLC calculated earnings per common unit by first deducting the amount of cumulative returns on both the Redeemable Preferred and Preferred units from net income (loss), and dividing this amount by the weighted average number of vested common units (including both the vested Class A common units and Class B units). For periods presented in which Southcross Energy LLC units were outstanding, no unvested common units were included in the computation of the diluted per unit amount because all would have been antidilutive to the net loss per common unit holder. The amount of unvested common units that were not included in the computation of diluted per unit amounts were 143,220 units for the period ended November 6, 2012.

Transaction-Related Costs

Transaction-Related Costs	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Business Combinations [Abstract]
Transaction-Related Costs	ACQUISITIONS TexStar Rich Gas System Transaction. On August 4, 2014, contemporaneously with the closing of the Holdings Transaction, TexStar contributed to us the TexStar Rich Gas System through a contribution of TexStar’s equity interest in the entities that own the TexStar Rich Gas System (the “Contribution”). In exchange for the Contribution, we paid $80 million in cash, assumed $100 million of debt (which was immediately repaid through our Term Loan Agreement (as defined in Note 6)) and issued 14,633,000 Class B Convertible Units (the “Class B Convertible Units”). The TexStar Rich Gas System consists of a cryogenic processing plant, located in Bee County, Texas, and joint venture ownership in natural gas gathering and residue pipelines across the core producing areas extending from Dimmit to Karnes Counties, Texas in the liquids-rich window of the Eagle Ford Shale region. These pipelines are operated under split-capacity arrangements within joint venture arrangements with Targa Pipeline Partners LP (see Note 13). The amount of the consideration paid over TexStar’s net book value of the assets received and liabilities assumed of the TexStar Rich Gas System was recorded as a reduction to partners’ capital as summarized as follows (in thousands): Consideration paid (1) $ 404,414 Current assets $ 1,295 Property, plant and equipment, net 255,220 Investments in joint ventures (2) 152,050 Total assets contributed 408,565 Total liabilities assumed (3) (102,776 ) Net identifiable assets contributed $ 305,789 Consideration paid in excess of net assets contributed $ 98,625 Allocation of reduction to partners' capital: Common limited partner interest $ 45,420 Class B Convertible limited partner interest 27,925 Subordinated limited partner interest 23,308 General Partner interest 1,972 Total reduction to partners' capital $ 98,625 (1) This amount was calculated as follows: $80 million of cash plus 14,633,000 Class B Convertible Units at an issue price of $22.17 , the closing price of the Partnership’s common units on August 4, 2014. (2) Significant assets acquired through the TexStar Rich Gas System Transaction include equity interests in three joint ventures. See Note 13. (3) This amount includes $100 million of debt assumed. Onyx Pipelines Acquisition. On March 6, 2014, our subsidiary, Southcross Nueces Pipelines LLC, acquired natural gas pipelines near Corpus Christi, Texas and contracts related to these pipelines from Onyx Midstream, LP and Onyx Pipeline Company (collectively, “Onyx”) for $38.6 million in cash, net of certain adjustments as provided in the purchase agreement. The pipelines transport natural gas to two power plants in Nueces County, Texas under fixed-fee contracts that extend through 2029 and include an option to extend the agreements by an additional term of up to ten years. The contracts were renegotiated in connection with the acquisition; therefore, we considered these contracts to be assumed at fair market value. The fair values of the property, plant and equipment were based upon assumptions related to expected future cash flows, discount rates and asset lives using currently available information. We utilized a mix of the cost, income and market approaches to determine the estimated fair values of such assets. The fair value measurements and models were classified as non-recurring Level 3 measurements. We performed our assessment of the fair value of the assets acquired and liabilities assumed, and the consideration given was considered equal to the fair value of net assets acquired. As a result, no goodwill was recorded. The assessment was finalized during the second quarter of 2014 and there were no subsequent changes to the preliminary balances recorded. The fair value of the assets acquired and liabilities assumed related to the Onyx purchase price was as follows (in thousands): Purchase Price—Cash $ 38,636 Current assets $ 730 Property, plant and equipment 39,413 Total assets acquired 40,143 Current liabilities assumed (1,407 ) Other liabilities assumed (100 ) Net identifiable assets acquired $ 38,636 Unaudited Pro Forma Financial Information for Onyx Pipelines Acquisition. The following unaudited pro forma financial information for the three months ended March 31, 2014 assumes that the acquisition of pipelines from Onyx occurred on January 1, 2013 and includes adjustments for income from operations, including depreciation and amortization, as well as the effects of financing the transaction (in thousands, except unit information): Three Months Ended March 31, 2014 Total revenue $ 214,240 Net loss (1,397 ) Net loss attributable to common unitholders (1,115 ) Net loss per common unit (basic and diluted) (0.06 ) Net loss attributable to subordinated unitholders (745 ) Net loss per subordinated unit (basic and diluted) (0.06 ) The unaudited pro forma information is not necessarily indicative of what our statements of operations would have been if the transaction had occurred on that date, or what the financial position or results from operations will be for any future periods. For the period from March 6, 2014 through March 31, 2014, the Onyx pipelines business contributed $0.3 million in revenues and $0.1 million in net income to our statements of operations. Texoz Acquisition. On November 21, 2014, we completed the acquisition of a natural gas gathering system in McMullen County, Texas (the “Texoz System”) from LT Gathering, LLC for $5.4 million in cash, net of certain adjustments as provided in the purchase agreement (the “Texoz Acquisition”). The Texoz System consists of eight miles of gathering pipelines within two miles of our existing rich gas pipeline network and services customers under acreage dedication contracts. Due to the immaterial amount of this transaction, no pro-forma financial information has been presented. Holdings Drop-Down Acquisition. On May 7, 2015, we completed the 2015 Holdings Acquisition 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. The acquired assets consist of the Valley Wells System, the Compression Assets and two NGL pipelines that were under construction at the time of the transaction (and that are now operational). Total consideration for the assets was $15.0 million in cash and 4.5 million new common units, valued as of the date of closing, issued to Holdings equating to $77.6 million . We also assumed the remaining capital expenditures for the completion of the NGL pipelines that were under construction. The Valley Wells System is located in the Eagle Ford Shale region, in La Salle County, Texas. The system has sour gas treating capacity of approximately 100 MMcf/d and is supported by a 35 MMcf/d minimum volume commitment. The system is connected to our rich gas system for transport and processing. The assets acquired in the 2015 Holdings Acquisition include over 50,000 horsepower of compression capability that serve both the Valley Wells and Lancaster gathering systems located primarily in Dimmit, Frio and LaSalle counties. The NGL pipelines, which were completed in June 2015, include a Y-grade pipeline that connects our Woodsboro processing facility to Holdings’ Robstown fractionator (“Robstown”) and a propane pipeline from our Bonnie View fractionator to Robstown. Because of the common control aspects in the 2015 Holdings Acquisition, 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. The acquired NGL pipelines were accounted for as an asset acquisition and will be included in the historical financial statements, and before May 7, 2015. The consolidated net assets associated with the Valley Wells System and Compression Assets as of March 31, 2015 were $88.8 million and are presented in the consolidated balance sheet of the Partnership. As a carve-out transaction, the 2015 Holdings Acquisition has no cash accounts. As such, accounts receivable and accounts payable, along with certain other assets and liabilities that would be settled in cash, were the rights and obligations of Holdings as of March 31, 2015. 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. Pooling of Interests. As noted above, the 2015 Holdings Acquisition was between commonly controlled entities which required that we account for the acquisitions in a manner similar to a pooling of interests. As a result, the historical financial statements of the Partnership and the Valley Wells System and Compression Assets have been combined to reflect the historical operations, financial position and cash flows from the date common control began on August 4, 2014. Revenues and net income for the previously separate entities and the combined amounts for the three months ended March 31, 2015, are as follows (in thousands): Three Months Ended March 31, 2015 Partnership revenues $ 180,549 Valley Wells System and Compression Assets revenue (1) 5,389 Combined revenues $ 185,938 Partnership net income $ (10,751 ) Valley Wells System and Compression Assets net loss (1) (3,154 ) Combined net income $ (13,905 ) (1) Results are fully reflected in the Partnership's results of operations for the three months ended March 31, 2015.	ACQUISITIONS TexStar Rich Gas System Transaction. On August 4, 2014, contemporaneously with the closing of the Holdings Transaction, TexStar contributed to us certain gathering and processing assets (the “TexStar Rich Gas System”), through a contribution of TexStar’s equity interest in the entities that own the TexStar Rich Gas System (the “Contribution”) to us. In exchange for the Contribution, we paid $80 million in cash, assumed $100 million of debt (which was immediately repaid through our Term Loan Agreement (as defined in Note 8)) and issued 14,633,000 Class B Convertible Units (the “Class B Convertible Units”). The TexStar Rich Gas System consists of a cryogenic processing plant, located in Bee County, Texas, and joint venture ownership in natural gas gathering and residue pipelines across the core producing areas extending from Dimmit to Karnes Counties, Texas in the liquids-rich window of the Eagle Ford Shale region. These pipelines are operated under split-capacity arrangements within joint venture arrangements with Atlas Pipeline Partners, L.P. The amount of the consideration paid over TexStar’s net book value of the assets received and liabilities assumed of the TexStar Rich Gas System is recorded as a reduction to partners’ capital as summarized as follows (in thousands): Consideration paid (1) $ 404,414 Current assets $ 1,295 Property, plant and equipment, net 255,220 Investments in joint ventures (2) 152,050 Total assets contributed 408,565 Total liabilities assumed (3) (102,776 ) Net identifiable assets contributed $ 305,789 Consideration paid in excess of net assets contributed $ 98,625 Allocation of reduction to partners' capital: Common limited partner interest $ 45,420 Class B Convertible limited partner interest 27,925 Subordinated limited partner interest 23,308 General Partner interest 1,972 Total reduction to partners' capital $ 98,625 ____________________________________________________________________________ (1) This amount was calculated as follows: $80 million of cash plus 14,633,000 Class B Convertible Units at an issue price of $22.17 , the closing price of the Partnership’s common units on August 4, 2014. (2) Significant assets acquired through the TexStar Rich Gas System Transaction include equity interests in three joint ventures. See Note 16. (3) This amount includes $100 million of debt assumed. Onyx Pipelines Acquisition. On March 6, 2014, our subsidiary, Southcross Nueces Pipelines LLC, acquired natural gas pipelines near Corpus Christi, Texas and contracts related to these pipelines from Onyx Midstream, LP and Onyx Pipeline Company (collectively, “Onyx”) for $38.6 million in cash, net of certain adjustments as provided in the purchase agreement. The pipelines transport natural gas to two power plants in Nueces County, Texas under fixed-fee contracts that extend through 2029 and include an option to extend the agreements by an additional term of up to ten years. The contracts were renegotiated in connection with the acquisition; therefore, we consider these contracts to be assumed at fair market value. The fair values of the property, plant and equipment are based upon assumptions related to expected future cash flows, discount rates and asset lives using currently available information. We utilized a mix of the cost, income and market approaches to determine the estimated fair values of such assets. The fair value measurements and models have been classified as non-recurring Level 3 measurements. We performed our assessment of the fair value of the assets acquired and liabilities assumed, and the consideration given was considered equal to the fair value of net assets acquired. As a result, no goodwill was recorded. The assessment was finalized during the second quarter of 2014 and there were no changes to the preliminary balances previously recorded. The fair value of the assets acquired and liabilities assumed related to the Onyx purchase price was as follows (in thousands): Purchase Price—Cash $ 38,636 Current assets $ 730 Property, plant and equipment 39,413 Total assets acquired 40,143 Current liabilities assumed (1,407 ) Other liabilities assumed (100 ) Net identifiable assets acquired $ 38,636 Unaudited Pro Forma Financial Information for Onyx Pipelines Acquisition. The following unaudited pro forma financial information for the year ended December 31, 2013 and the year ended December 31, 2014 assumes that the acquisition of pipelines from Onyx occurred on January 1, 2013 and includes adjustments for income from operations, including depreciation and amortization, as well as the effects of financing the transaction (in thousands, except unit information): Year Ended December 31, 2014 2013 Total revenue $ 843,376 $ 639,104 Net loss (31,400 ) (18,306 ) Net loss attributable to common unitholders (20,211 ) (9,934 ) Net loss per common unit (basic and diluted) (0.85 ) (0.68 ) Net loss attributable to subordinated unitholders (8,373 ) (9,678 ) Net loss per subordinated unit (basic and diluted) (0.69 ) (0.79 ) The unaudited pro forma information is not necessarily indicative of what our statements of operations would have been if the transaction had occurred on that date, or what the financial position or results from operations will be for any future periods. For the year ended December 31, 2014, the Onyx pipelines business contributed $4.2 million in revenues and $1.3 million in net income to our statements of operations. Texoz Acquisition. On November 21, 2014, we completed the acquisition of a natural gas gathering system in McMullen County, Texas (the “Texoz System”) from LT Gathering, LLC for $5.4 million in cash, net of certain adjustments as provided in the purchase agreement (the “Texoz Acquisition”). The Texoz System consists of eight miles of gathering pipelines within two miles of our existing rich gas pipeline network and services customers under acreage dedication contracts. Due to the immaterial amount of this transaction, no pro-forma financial information was disclosed in this report. Holdings Drop-Down Acquisition. On May 7, 2015, we completed the 2015 Holdings Acquisition 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. The acquired assets consist of the Valley Wells System, Compression Assets and two NGL pipelines that were under construction at the time of the transaction (and that are now operational). Total consideration for the assets was $15.0 million in cash and 4.5 million new common units, valued as of the date of closing, issued to Holdings equating to $77.6 million . We also assumed the remaining capital expenditures for the completion of the NGL pipelines that were under construction. The Valley Wells System is located in the Eagle Ford Shale region, in La Salle County, Texas. The system has sour gas treating capacity of approximately 100 MMcf/d and is supported by a 35 MMcf/d minimum volume commitment. The system is connected to our rich gas system for transport and processing. The assets acquired in the 2015 Holdings Acquisition include over 50,000 horsepower of compression capability that serve both the Valley Wells and Lancaster gathering systems located primarily in Dimmit, Frio and LaSalle counties. The NGL pipelines, which were completed in June 2015, include a Y-grade pipeline that connects our Woodsboro processing facility to Holdings’ Robstown fractionator (“Robstown”) and a propane pipeline from our Bonnie View fractionator to Robstown. Because of the common control aspects in the 2015 Holdings Acquisition, 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 consolidated net assets associated with the Valley Wells System and Compression Assets as of December 31, 2014 were $77.3 million and are presented in the consolidated balance sheet of the Partnership. The acquired NGL pipelines were accounted for as an asset acquisition and will be included in the historical financial statements beginning on May 7, 2015. As a carve-out transaction, the 2015 Holdings Acquisition has no cash accounts. As such, accounts receivable and accounts payable, along with certain other assets and liabilities that would be settled in cash, were the rights and obligations of Holdings as of December 31, 2014. Given their nature and the fact that carve-out financial statements are meant to represent an entity’s operations as if it had existed as of the time common control occurred, we have presented these amounts as third-party receivables and payables. Pooling of Interests. 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 year ended December 31, 2014, are as follows (in thousands): Year Ended December 31, 2014 Partnership revenues $ 842,728 Valley Wells System and Compression Assets revenue (1) 5,785 Combined revenues $ 848,513 Partnership net loss $ (31,322 ) Valley Wells System and Compression Assets net loss (1) (6,409 ) Combined net loss $ (37,731 ) _________________________________ (1) Results are fully reflected in the Partnership's results of operations for the year ended December 31, 2014. TRANSACTION-RELATED COSTS During the year ended December 31, 2014, we recognized $9.9 million of transaction-related costs in connection with the Onyx acquisition, the Holdings Transaction, the TexStar Rich Gas System Transaction and the Texoz Acquisition, which are recorded in operations and maintenance and general and administrative expenses. For the year ended December 31, 2014, these costs include (a) $7.2 million related to the accelerated vesting of the LTIP awards (as defined in Note 5) due to the change in control as further discussed in Note 14, (b) $1.7 million of advisory, audit and legal fees, (c) $0.6 million of charges associated with employees’ severance, (d) $0.3 million related to professional fees associated with the Onyx acquisition and the Texoz Acquisition and (e) $0.1 million related to the accelerated vesting of the Southcross Energy LLC equity equivalent units due to the change in control as further discussed in Note 14. We expect to incur additional costs relating to integration and other activities throughout 2015.

FINANCIAL INSTRUMENTS

FINANCIAL INSTRUMENTS	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Investments, All Other Investments [Abstract]
FINANCIAL INSTRUMENTS	FINANCIAL INSTRUMENTS Fair Value Measurements We apply recurring fair value measurements to our financial assets and liabilities. In estimating fair value, we generally use a market approach and incorporate assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and/or the risks inherent in the inputs to the valuation techniques. The fair value measurement inputs we use vary from readily observable inputs that represent market data obtained from independent sources to unobservable inputs that reflect our own market assumptions that cannot be validated through external pricing sources. Based on the observability of the inputs used in the valuation techniques, the financial assets and liabilities carried at fair value in the financial statements are classified as follows: • Level 1—Represents unadjusted quoted market prices in active markets for identical assets or liabilities that are accessible at the measurement date. This category primarily includes our cash and cash equivalents, accounts receivable and accounts payable. • Level 2—Represents quoted market prices for similar assets or liabilities in active markets, quoted market prices in markets that are not active or other inputs that are observable or can be corroborated by observable market data. This category primarily includes variable rate debt, over-the-counter swap contracts based upon natural gas price indices and interest rate derivative transactions. • Level 3—Represents derivative instruments whose fair value is estimated based on internally developed models and methodologies utilizing significant inputs that are generally less readily observable from market sources. We do not have financial assets and liabilities classified as Level 3. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the level in the fair value hierarchy must be determined based on the lowest level input that is significant to the fair value measurement. An assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and consideration of factors specific to the asset or liability. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable represent fair values based on the short-term nature of these instruments. The fair value of the debt funded through our credit facilities approximates its carrying amount due primarily to the variable nature of the interest rate of the instrument and is considered a Level 2 fair value measurement. Derivative Financial Instruments Interest Rate Derivative Transactions We manage a portion of our interest rate risk through interest rate swaps. In March 2012, we terminated an interest rate cap contract and entered into an interest rate swap contract with Wells Fargo, N.A. The interest rate swap had a notional value of $150.0 million , and a maturity date of June 30, 2014. We received a floating rate based upon one-month London Interbank Offered Rate (“LIBOR”) and paid a fixed rate under the interest rate swap of 0.54% . The interest rate swap was designated as a cash flow hedge for accounting purposes at inception of the contract and, thus, to the extent the cash flow hedge was effective, unrealized gains and losses were recorded to accumulated other comprehensive income/loss and recognized in interest expense as the underlying hedged transactions (interest payments) were recorded. Any hedge ineffectiveness was recognized in interest expense immediately. We did not have any hedge ineffectiveness during the three months ended March 31, 2014. In February 2014, we discontinued cash flow hedge accounting on a prospective basis as a result of the $148.5 million repayment of borrowings under our Previous Credit Facility (as defined in Note 6). The fair value of the interest rate swap recorded in accumulated other comprehensive loss at the cash flow hedge de-designation date was $0.1 million . This balance was reclassified into interest expense as interest on the hedged debt was recorded. No ineffectiveness was recorded as a result of the cash flow hedge de-designation. Changes in the fair value of the interest rate swap for the remainder of the contract term were recognized in interest expense. 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. These interest rate swaps are not designated as cash flow hedges and as a result, changes in the fair value of the interest rate swaps are recognized in interest expense immediately. Our interest rate swap position was as follows (in thousands): Estimated Fair Value Notional Amount Fixed Rate Effective Date Maturity Date March 31, 2015 $ 140,000 0.327 % June 30, 2014 June 30, 2015 $ (51 ) 50,000 1.198 % September 30, 2014 June 30, 2016 (94 ) 50,000 1.196 % September 30, 2014 June 30, 2016 (94 ) $ (239 ) In December 2014, we entered into an interest rate cap contract for $20.0 million notional value, effective December 31, 2014, with a maturity date of December 31, 2016. The contract effectively caps our LIBOR-based interest rate on that portion of debt at 1.5% . We did not designate the interest rate cap as a hedging instrument 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. The fair values of our interest rate derivatives were as follows (in thousands): r Significant Other Observable Inputs (Level 2) Fair Value Measurement as of March 31, 2015 December 31, 2014 Current interest rate derivative assets $ 13 $ 27 Non-current interest rate derivative assets $ 10 $ 27 Current interest rate derivative (liabilities) $ (202 ) $ (175 ) Non-current interest rate derivative (liabilities) $ (37 ) $ (39 ) Total interest rate derivatives $ (216 ) $ (160 ) The effect of the interest rate swap designated as a cash flow hedge in our statements of changes in partners’ capital and comprehensive loss was as follows (in thousands): Three Months Ended March 31, 2015 2014 Change in value recognized in other comprehensive loss - effective portion $ — $ (11 ) Loss reclassified from accumulated other comprehensive loss to interest expense — 115 There were no amounts of gains or losses reclassified into earnings as a result of the discontinuance of cash flow hedge accounting due to the lack of probability of the forecasted transaction occurring. The realized and unrealized amounts recognized in interest expense associated with derivatives that are not designated as hedging instruments were as follows (in thousands): Three Months Ended March 31, 2015 2014 Unrealized loss on interest rate derivatives $ 56 $ 12 Realized loss on interest rate derivatives 104 27 Commodity Swaps In our normal course of business, we periodically enter into month-ahead swap contracts to hedge our exposure to certain intra-month natural gas index pricing risk. We had no outstanding month-ahead swap contracts as of March 31, 2015. The total volume of outstanding month-ahead swap contracts as of December 31, 2014 was 12,000 MMBtu per day. 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. We have elected to present our commodity swaps net on the balance sheets. We did not have any cash collateral received or paid on our commodity swaps as of March 31, 2015 or December 31, 2014. The effect of offsetting on our balance sheets was as follows (in thousands): March 31, 2015 December 31, 2014 Other Current Assets Other Current Liabilities Other Current Assets Other Current Liabilities Gross amounts of recognized assets (liabilities) $ — $ — $ 112 $ — Gross amounts offset on the balance sheets — — — — Net amount $ — $ — $ 112 $ — The realized and unrealized gain/loss on these derivatives, recognized in revenues in our statements of operations, was as follows (in thousands): Three Months Ended March 31, 2015 2014 Realized gain (loss) on commodity swap derivatives $ 125 $ (1,169 ) Unrealized gain (loss) on commodity swap derivatives (111 ) 44	FINANCIAL INSTRUMENTS Fair Value Measurements We apply recurring fair value measurements to our financial assets and liabilities. In estimating fair value, we generally use a market approach and incorporate assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and/or the risks inherent in the inputs to the valuation techniques. The fair value measurement inputs we use vary from readily observable inputs that represent market data obtained from independent sources to unobservable inputs that reflect our own market assumptions that cannot be validated through external pricing sources. Based on the observability of the inputs used in the valuation techniques, the financial assets and liabilities carried at fair value in the financial statements are classified as follows: • Level 1—Represents unadjusted quoted market prices in active markets for identical assets or liabilities that are accessible at the measurement date. This category primarily includes our cash and cash equivalents, accounts receivable and accounts payable. • Level 2—Represents quoted market prices for similar assets or liabilities in active markets, quoted market prices in markets that are not active or other inputs that are observable or can be corroborated by observable market data. This category primarily includes variable rate debt, over-the-counter swap contracts based upon natural gas price indices and interest rate derivative transactions. • Level 3—Represents derivative instruments whose fair value is estimated based on internally developed models and methodologies utilizing significant inputs that are generally less readily observable from market sources. We do not have financial assets and liabilities classified as Level 3. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the level in the fair value hierarchy must be determined based on the lowest level input that is significant to the fair value measurement. An assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and consideration of factors specific to the asset or liability. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable represent fair values based on the short-term nature of these instruments. The fair value of the debt funded through our credit facilities approximates its carrying amount due primarily to the variable nature of the interest rate of the instrument and is considered a Level 2 fair value measurement. Derivative Financial Instruments Interest Rate Derivative Transactions We manage a portion of our interest rate risk through interest rate swaps. In March 2012, we terminated an interest rate cap contract and entered into an interest rate swap contract with Wells Fargo, N.A. The interest rate swap had a notional value of $150.0 million , and a maturity date of June 30, 2014. We received a floating rate based upon one -month LIBOR and paid a fixed rate under the interest rate swap of 0.54% . The interest rate swap was designated as a cash flow hedge for accounting purposes at inception of the contract and, thus, to the extent the cash flow hedge was effective, unrealized gains and losses were recorded to accumulated other comprehensive income/loss and recognized in interest expense as the underlying hedged transactions (interest payments) were recorded. Any hedge ineffectiveness was recognized in interest expense immediately. We did not have any hedge ineffectiveness during the years ended December 31, 2014 and 2013. In February 2014, we discontinued cash flow hedge accounting on a prospective basis as a result of the $148.5 million repayment of borrowings under our Previous Credit Facility (as defined in Note 8). The fair value of the interest rate swap recorded in accumulated other comprehensive loss at the cash flow hedge de-designation date was $0.1 million . This balance was reclassified into interest expense as interest on the hedged debt was recorded. No ineffectiveness was recorded as a result of the cash flow hedge de-designation. Changes in the fair value of the interest rate swap for the remainder of the contract term were recognized in interest expense. 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. These interest rate swaps are not designated as cash flow hedges and as a result, changes in the fair value of the interest rate swaps are recognized in interest expense immediately. We have elected to present our interest rate swaps net on the balance sheets. There was no effect of offsetting on the balance sheets for the years ended December 31, 2014 and 2013. Our interest rate swap position was as follows (in thousands): Estimated Fair Value Notional Amount Fixed Rate Effective Date Maturity Date December 31, 2014 $ 140,000 0.327 % June 30, 2014 June 30, 2015 $ (97 ) 50,000 1.198 % September 30, 2014 June 30, 2016 (59 ) 50,000 1.196 % September 30, 2014 June 30, 2016 (58 ) $ (214 ) In December 2014, we entered into an interest rate cap contract for $20.0 million notional value, effective December 31, 2014, with a maturity date of December 31, 2016. The contract effectively caps our LIBOR-based interest rate on that portion of debt at 1.5% . We did not designate the interest rate cap as a hedging instrument 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. 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 December 31, 2014 December 31, 2013 Current interest rate derivative assets $ 27 $ — Non-current interest rate derivative assets $ 27 $ — Current interest rate derivative (liabilities) $ (175 ) $ (263 ) Non-current interest rate derivative (liabilities) $ (39 ) $ — Total interest rate derivatives $ (160 ) $ (263 ) The effect of the interest rate swap designated as a cash flow hedge in our statements of changes in partners’ capital and members’ equity and comprehensive loss was as follows (in thousands): Year Ended December 31, 2014 2013 2012 Change in value recognized in other comprehensive loss - effective portion $ (11 ) $ (148 ) $ (745 ) Loss reclassified from accumulated other comprehensive loss to interest expense $ 221 $ 415 $ 268 There were no amounts of gains or losses reclassified into earnings as a result of the discontinuance of cash flow hedge accounting due to the lack of probability of the forecasted transaction occurring. The realized and unrealized amounts recognized in interest expense associated with derivatives that are not designated as hedging instruments were as follows (in thousands): Year Ended December 31, 2014 2013 2012 Unrealized loss on interest rate derivatives $ 160 $ — $ 141 Realized loss on interest rate derivatives $ 316 $ 108 $ 82 Commodity Swaps In our normal course of business, we periodically enter into month-ahead swap contracts to hedge our exposure to certain intra-month natural gas index pricing risk. The total volume of outstanding month-ahead swap contracts as of December 31, 2014 and 2013 was 12,000 MMBtu per day and 33,722 MMBtu per day, respectively. We had no outstanding month-ahead swap contracts as of December 31, 2012. We define these contracts as Level 2 because the index price associated with such contracts is observable and tied to a similarly quoted first-of-the-month natural gas index price. We have elected to present our commodity swaps net on the balance sheets. We did not have any cash collateral received or paid on our commodity swaps as of December 31, 2014 or 2013. The effect of offsetting on our balance sheets were as follows (in thousands): December 31, 2014 December 31, 2013 Other Current Assets Other Current Liabilities Other Current Assets Other Current Liabilities Gross amounts of recognized assets (liabilities) $ 112 $ — $ 140 $ (20 ) Gross amounts offset on the balance sheets — — (20 ) 20 Net amount 112 — 120 — The realized and unrealized gain/loss on these derivatives, recognized in revenues in our statements of operations, were as follows (in thousands): Year ended December 31, 2014 2013 2012 Realized (loss) gain on commodity swap derivatives $ 347 $ (659 ) $ (12 ) Unrealized (loss) gain on commodity swap derivatives (8 ) 120 —

LONG-LIVED ASSETS

LONG-LIVED ASSETS	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
LONG-LIVED ASSETS	LONG-LIVED ASSETS Property, Plant and Equipment Property, plant and equipment consisted of the following (in thousands): Estimated Useful Life (yrs) March 31, 2015 December 31, 2014 Pipelines 15-30 $ 503,888 $ 488,592 Gas processing, treating and other plants 15 532,538 515,080 Compressors 7-15 64,856 62,741 Rights of way and easements 15 37,263 37,238 Furniture, fixtures and equipment 5 3,735 3,671 Capital lease vehicles 3-5 2,284 2,076 Total property, plant and equipment 1,144,564 1,109,398 Accumulated depreciation and amortization (159,252 ) (142,234 ) Total 985,312 967,164 Construction in progress 51,319 63,858 Land and other 24,002 27,548 Property, plant and equipment, net $ 1,060,633 $ 1,058,570 Depreciation is provided using the straight-line method based on the estimated useful life of each asset. In January 2015, we shut down our Gregory facility for four weeks due to a fire at the facility. In connection with the fire, as of March 31, 2015, the amount we had spent as part of efforts to return the facility to service did not exceed our insurance deductible. Intangible Assets Intangible assets of $1.5 million as of March 31, 2015 and December 31, 2014, respectively, represent the unamortized value assigned to long-term supply and gathering contracts acquired in 2011. 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.	LONG-LIVED ASSETS Property, Plant and Equipment Property, plant and equipment consist of the following (in thousands): Estimated Useful Life As of December 31, 2014 2013 Pipelines 15-30 $ 488,592 $ 344,721 Gas processing, treating and other plants 15 515,080 254,133 Compressors 7-15 62,741 20,030 Rights of way and easements 15 37,238 20,729 Furniture, fixtures and equipment 5 3,671 3,347 Capital lease vehicles 3-5 2,076 1,396 Total property, plant and equipment 1,109,398 644,356 Accumulated depreciation and amortization (142,234 ) (79,908 ) Total 967,164 564,448 Construction in progress 63,858 6,039 Land and other 27,548 5,308 Property, plant and equipment, net $ 1,058,570 $ 575,795 Depreciation is provided using the straight-line method based on the estimated useful life of each asset. Depreciation expense for the years ended December 31, 2014, 2013 and 2012 was $46.1 million , $33.5 million and $19.0 million , respectively. In January 2013, we shut down our Gregory facility to perform extensive turnaround maintenance activities and to connect additional equipment to enhance NGL recoveries. As the turnaround maintenance was nearing completion, we experienced a fire at this facility. In connection with the fire, as of December 31, 2014, we spent $5.5 million to return the facility to service and filed an insurance claim related to these costs. We recovered $1.0 million in 2013 and $3.9 million in 2014 from insurance proceeds for this loss, less a $0.3 million deductible, under our insurance policies. We received the remaining approximately $0.6 million outstanding at December 31, 2014 in January 2015. Intangible Assets Intangible assets of $1.5 million and $1.6 million as of December 31, 2014 and 2013, respectively, represent the unamortized value assigned to long-term supply and gathering contracts acquired in 2011. 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.

LONG-TERM DEBT

LONG-TERM DEBT	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT Our outstanding debt and related information at March 31, 2015 and December 31, 2014 are as follows (in thousands): March 31, 2015 December 31, 2014 Revolving credit facility due 2019 $ 65,000 $ 30,000 Term loans (including OID of $2.1 million) due 2021 444,592 445,629 Total long-term debt (including current portion) 509,592 475,629 Current portion of long-term debt $ (4,500 ) $ (4,500 ) Total long-term debt $ 505,092 $ 471,129 Outstanding letters of credit $ 20,830 $ 30,130 Remaining unused borrowings $ 114,170 $ 139,870 Three Months Ended March 31, 2015 2014 Weighted average interest rate 5.1 % 4.6 % Average outstanding borrowings $ 512,093 $ 192,403 Maximum borrowings $ 522,750 $ 267,300 Previous Credit Facility In November 2012, we entered into a five -year $350.0 million revolving credit facility (as amended, the “Previous Credit Facility”). Borrowings under the Previous Credit Facility were set to mature in November 2017. We utilized the Previous Credit Facility for working capital requirements and capital expenditures, the purchase of assets, the payment of distributions and other general purposes. During 2013 and the first quarter of 2014, we entered into a total of four amendments to the Previous Credit Facility. In connection with these amendments, our availability was reduced from $350.0 million to the sum of $250.0 million plus any amounts placed on deposit in a collateral account of our General Partner and letters of credit outstanding. This availability was increased to $350.0 million in connection with the fourth amendment in March 2014. In connection with the closing of the TexStar Rich Gas System Transaction, we refinanced our Previous Credit Facility and entered into the Senior Credit Facilities (as defined below). Senior Credit Facilities On August 4, 2014, in connection with the consummation of the Contribution and TexStar Rich Gas System Transaction, we entered into (a) a Third Amended and Restated Revolving Credit Agreement with Wells Fargo Bank, N.A., as Administrative Agent, UBS Securities LLC and Barclays Bank PLC, as Co-Syndication Agents, JPMorgan Chase Bank, N.A., as Documentation Agent, and a syndicate of lenders (the “Third A&R Revolving Credit Agreement”) and (b) a Term Loan Credit Agreement with Wells Fargo Bank, N.A., as Administrative Agent, UBS Securities LLC and Barclays Bank PLC, as Co-Syndication Agents, and a syndicate of lenders (the “Term Loan Agreement” and, together with the Third A&R Revolving Credit Agreement, the “Senior Credit Facilities”). The initial borrowings and extensions of credit under the Term Loan Agreement were used to finance the TexStar Rich Gas System Transaction (including the immediate repayment of the $100 million of debt assumed in the transaction), the repayment of certain of our existing debt and the payment of fees and expenses in connection with the new debt arrangements and ongoing working capital and other general partnership purposes. No amounts were initially drawn on the Third A&R Revolving Credit Agreement. Substantially all of our assets are pledged as collateral under the Senior Credit Facilities, with the security interest of the facilities ranking pari passu. Third A&R Revolving Credit Agreement The Third A&R Revolving Credit Agreement is a five-year $200 million revolving credit facility (the “Credit Facility”). Borrowings under our Credit Facility bear interest at the LIBOR plus an applicable margin or a base rate as defined in the respective credit agreement. Pursuant to the Third A&R Revolving Credit Agreement, among other things: (a) the letters of credit sublimit increased to $75 million ; (b) we have the right to increase the total commitments under the Credit Facility by obtaining additional commitments from other lenders, as long as our senior secured leverage ratio is less than or equal to 4.50 to 1.00 before and after giving effect to such increase, subject to certain other conditions; (c) the definition of “Change of Control” is amended to permit the combination transaction with TexStar and to reflect the Sponsors’ control of the General Partner; (d) our maximum consolidated total leverage ratio (i) was set at 5.75 to 1.00 as of the last day of the fiscal quarter ending each of September 30, 2014 and December 31, 2014, (ii) is set at 5.50 to 1.00 as of the last day of the fiscal quarter ending March 31, 2015, (iii) 5.25 to 1.00 as of the last day of the fiscal quarter ending June 30, 2015 and (iv) 5.00 to 1.00 as of the last day of each fiscal quarter thereafter; (e) we had the right, exercisable on or before the date that our annual audited financial statements were due for the 2014 fiscal year, to comply with the consolidated total leverage ratio, consolidated senior secured leverage ratio and the consolidated interest coverage ratio covenants (the “Financial Covenants”) by applying certain specified quarterly base periods and annualization methods pertaining to the TexStar Rich Gas System; (f) if we fail to comply with the Financial Covenants (a “Financial Covenant Default”), we have the right (which cannot be exercised more than two times in any 12-month period or more than four times during the term of the facility) 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; (g) certain definitions are amended to take into account the TexStar Rich Gas System; and (h) the negative covenants are amended to permit the entry into, and indebtedness under, the Term Loan Agreement. On May 7, 2015, we entered into a first amendment to our Third A&R Revolving Credit Agreement that provides for more favorable financial covenants through the third quarter of 2016 and an equity cure that is available through then end of 2016. See Note 15. Term Loan Agreement The Term Loan Agreement is a seven-year $450 million senior secured term loan facility. On August 4, 2014, the lenders funded the full amount of the facility. Borrowings under our Term Loan Agreement bear interest at LIBOR plus 4.25% or a base rate as defined in the respective credit agreement with a LIBOR floor of 1.00% . Under the Term Loan Agreement, among other things: (a) subject to certain requirements, including the absence of a default and pro forma compliance under the Third A&R Revolving Credit Agreement and pro forma compliance with a senior secured leverage ratio less than or equal to 4.50 to 1.00 before and after giving effect to such increase, we may from time to time request incremental term loan commitments subject to certain other conditions; (b) we may seek commitments from third party lenders in connection with any incremental term loan commitment requests, subject to certain consent rights given to the administrative agent; (c) the guarantors and the collateral are the same as provided for the benefits of the lenders in the Third A&R Revolving Credit Agreement; (d) subject to certain conditions, we may request that the lenders extend the seven-year maturity of all or a portion of the outstanding loans under the facility; (e) the facility will amortize 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; (f) there are customary mandatory prepayment provisions and, subject to certain conditions, permissive prepayment provisions; provided, that if certain repricing transactions occur, we must pay a call premium equal to 1% of the principal amount of the loans subject to the repricing transactions; and (g) there are customary representations and warranties, affirmative covenants, negative covenants and provisions governing an event of default (including acceleration of payment in connection with material indebtedness, including the Third A&R Revolving Credit Agreement).	LONG-TERM DEBT Our outstanding debt and related information at December 31, 2014 and December 31, 2013 are as follows (in thousands): As of December 31, 2014 2013 Credit facility due 2019 $ 30,000 $ 267,300 Term loans (including OID of $2.1 million) due 2021 445,629 — Total long-term debt (including current portion) $ 475,629 $ 267,300 Current portion of long-term debt $ (4,500 ) $ — Total long-term debt $ 471,129 $ 267,300 Outstanding letters of credit $ 30,130 $ 31,260 Remaining unused borrowings $ 139,870 $ 69 Year Ended December 31, 2014 2013 Weighted average interest rate 4.6 % 4.4 % Average outstanding borrowings $ 308,670 $ 243,920 Maximum borrowings $ 491,875 $ 267,300 Total 2015 2016 2017 2018 2019 Thereafter Maturity Long-term debt $ 475,629 $ 4,500 $ 4,500 $ 4,500 $ 4,500 $ 34,500 $ 423,129 Previous Credit Facility In November 2012, we entered into a five -year $350.0 million revolving credit facility (as amended, the “Previous Credit Facility”). Borrowings under the Previous Credit Facility were set to mature in November 2017. We utilized the Previous Credit Facility for working capital requirements and capital expenditures, the purchase of assets, the payment of distributions and other general purposes. During 2013 and the first quarter of 2014, we entered into a total of four amendments to the Previous Credit Facility, primarily as a result of some operational challenges including the start up of our Bonnie View fractionator and the January 2013 fire at our Gregory facility. These impacted our operating results adversely and resulted in the need for the various amendments to our Previous Credit Facility. In connection with these amendments, our availability was reduced from $350.0 million to the sum of $250.0 million , plus any amounts placed on deposit in a collateral account of our General Partner and letters of credit outstanding. This availability was increased to $350.0 million in connection with the fourth amendment in March 2014. In connection with the closing of the TexStar Rich Gas System Transaction, we refinanced our Previous Credit Facility and entered into the Senior Credit Facilities (as defined below). Senior Credit Facilities On August 4, 2014, in connection with the consummation of the Contribution, we entered into (a) a Third Amended and Restated Revolving Credit Agreement with Wells Fargo Bank, N.A., as Administrative Agent, UBS Securities LLC and Barclays Bank PLC, as Co-Syndication Agents, JPMorgan Chase Bank, N.A., as Documentation Agent, and a syndicate of lenders (the “Third A&R Revolving Credit Agreement”) and (b) a Term Loan Credit Agreement with Wells Fargo Bank, N.A., as Administrative Agent, UBS Securities LLC and Barclays Bank PLC, as Co-Syndication Agents, and a syndicate of lenders (the “Term Loan Agreement” and, together with the Third A&R Revolving Credit Agreement, the “Senior Credit Facilities”). The initial borrowings and extensions of credit under the Term Loan Agreement were used to finance the TexStar Rich Gas System Transaction (including the immediate repayment of the $100 million of debt assumed in the transaction), the repayment of certain of our existing debt and the payment of fees and expenses in connection with the new debt arrangements and ongoing working capital and other general partnership purposes. No amounts were initially drawn on the Third A&R Revolving Credit Agreement. Substantially all of our assets are pledged as collateral under the Senior Credit Facilities, with the security interest of the facilities ranking pari passu. See Note 2. Third A&R Revolving Credit Agreement The Third A&R Revolving Credit Agreement is a five -year $200 million revolving credit facility (the “Credit Facility”). Borrowings under our Credit Facility bear interest at the London Interbank Offered Rate (“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 increased to $75.0 million ; (b) we have the right to increase the total commitments under the Credit Facility by obtaining additional commitments from other lenders, as long as our senior secured leverage ratio is less than or equal to 4.50 to 1.00 before and after giving effect to such increase, subject to certain other conditions; (c) the definition of “Change of Control” was amended to permit the combination transaction with TexStar and to reflect the Sponsors’ control of the General Partner; (d) our maximum consolidated total leverage ratio is set at (i) 5.75 to 1.00 as of the last day of the fiscal quarter ending December 31, 2014, (ii) 5.50 to 1.00 as of the last day of the fiscal quarter ending March 31, 2015, (iii) 5.25 to 1.00 as of the last day of the fiscal quarter ending June 30, 2015 and (iv) 5.00 to 1.00 as of the last day of each fiscal quarter thereafter, in each case, without any step-ups in connection with acquisitions; (e) we have the right, exercisable on or before the date that our annual audited financial statements are due for the 2014 fiscal year, to comply with the consolidated total leverage ratio, consolidated senior secured leverage ratio and the consolidated interest coverage ratio covenants (the “Financial Covenants”) by applying certain specified quarterly base periods pertaining to the TexStar Rich Gas System; (f) if we fail to comply with the Financial Covenants (a “Financial Covenant Default”), we have the right (which cannot be exercised more than two times in any twelve month period or more than four times during the term of the facility) to cure such Financial Covenant Default by having our 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; (g) certain definitions are amended to take into account the TexStar Rich Gas System; and (h) the negative covenants are amended to permit the entry into, and indebtedness under, the Term Loan Agreement. Term Loan Agreement The Term Loan Agreement is a seven-year $450 million senior secured term loan facility (the "Term Loan"). On August 4, 2014, the lenders funded the full amount of the facility. Borrowings under our Term Loan Agreement bear interest at LIBOR plus 4.25% or a base rate as defined in the respective credit agreement with a LIBOR floor of 1.00% . Under the Term Loan Agreement, among other things: (a) subject to certain requirements, including the absence of a default and pro forma compliance under the Third A&R Revolving Credit Agreement and pro forma compliance with a senior secured leverage ratio less than or equal to 4.50 to 1.00 before and after giving effect to such increase, we may from time to time request incremental term loan commitments subject to certain other conditions; (b) we may seek commitments from third party lenders in connection with any incremental term loan commitment requests, subject to certain consent rights given to the administrative agent; (c) the guarantors and the collateral are the same as provided for the benefits of lenders in the Third A&R Revolving Credit Agreement; (d) subject to certain conditions, we may request that the lenders extend the seven-year maturity of all or a portion of the outstanding loans under the facility; (e) the facility will amortize in equal quarterly installments of $1.125 million in an aggregate annual amount equal to 1% of the original principal amount of the initial loan, with the remainder due on the maturity date; (f) there are customary mandatory prepayment provisions and, subject to certain conditions, permissive prepayment provisions; provided, that if certain repricing transactions occur, we must pay a call premium equal to 1% of the principal amount of the loans subject to the repricing transactions; and (g) there are customary representations and warranties, affirmative covenants, negative covenants and provisions governing an event of default (including acceleration of payment in connection with material indebtedness, including the Third A&R Revolving Credit Agreement). See Note 2 for further detail.

COMMITMENTS AND CONTINGENT LIAB

COMMITMENTS AND CONTINGENT LIABILITIES	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENT LIABILITIES	COMMITMENTS AND CONTINGENCIES Legal Matters On March 5, 2013, one of our subsidiaries, Southcross Marketing Company Ltd., filed suit in a District Court of Dallas County against Formosa Hydrocarbons Company, Inc. (“Formosa”). The lawsuit sought recoveries of losses that we believe our subsidiary experienced as a result of the failure of Formosa to perform certain obligations under the gas processing and sales contract between the parties. Formosa filed a response generally denying our claims and, later, Formosa filed a counterclaim against our subsidiary claiming our subsidiary breached the gas processing and sales contract and a related agreement between the parties for the supply by Formosa of residue gas to a third party on behalf of our subsidiary. After a bench trial held in January 2015, on February 5, 2015, the judge ruled that Formosa breached certain of its obligations under the gas processing and sales contract and that our subsidiary breached an obligation under each of the gas processing and sales contract and the related residue gas agreement. The amount of damages awarded to our subsidiary was in excess of the damages awarded to Formosa. Rather than wait for the judge to award attorneys’ fees for each party as to the claims on which it prevailed, the parties have reached an agreement as to the appropriate award of attorneys’ fees. The amount of attorneys’ fees to be paid to our subsidiary is in excess of the attorneys’ fees to be paid to Formosa. Our subsidiary has filed a motion for reconsideration regarding a claim that was dismissed before trial through summary judgment. Formosa has filed its own motion for reconsideration regarding the amount of damages awarded to our subsidiary on one of its claims. Even if Formosa is successful in its request to reduce the damages awarded to our subsidiary, the amount of damages awarded to our subsidiary would still be in excess of the damages awarded to Formosa. A hearing has been scheduled for June 5, 2015 on both parties’ motions. No judgment will be entered until the judge has made a ruling on these motions. Regardless of how the judge rules on these motions, the judgment is not expected to have a material impact on our results of operations, cash flows or financial condition. With the filing of this motion, we now expect a final judgment to be entered in the third quarter of 2015, which may be extended or appealed. 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. 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 2015 to 2019. We recorded amortization expense related to the capital leases of $0.1 million for each of the three months ended March 31, 2015 and 2014. Capital leases entered into during the three months ended March 31, 2015 and 2014 were $0.2 million and $0.3 million , respectively. The capital lease obligation amounts included on the balance sheets were as follows (in thousands): March 31, 2015 December 31, 2014 Other current liabilities $ 451 $ 455 Other non-current liabilities 649 578 Total $ 1,100 $ 1,033 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 2015 to 2025. Expenses associated with operating leases, which are recorded in operations and maintenance expenses and general and administrative expenses in our statements of operations, were $1.2 million and $0.3 million for the three months ended March 31, 2015 and 2014, respectively. Purchase Commitments At March 31, 2015, we had commitments of approximately $18.3 million for purchases of material and equipment related to our capital projects, primarily related to the purchase of pipelines and compressors for our various capital expansion projects. We have other planned capital projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.	COMMITMENTS AND CONTINGENT LIABILITIES Legal Matters On March 5, 2013, one of our subsidiaries, Southcross Marketing Company Ltd., filed suit in a District Court of Dallas County against Formosa Hydrocarbons Company, Inc. (“Formosa”). The lawsuit sought recoveries of losses that we believe our subsidiary experienced as a result of the failure of Formosa to perform certain obligations under the gas processing and sales contract between the parties. Formosa filed a response generally denying our claims and, later, Formosa filed a counterclaim against our subsidiary claiming our affiliate breached the gas processing and sales contract and a related agreement between the parties for the supply by Formosa of residue gas to a third party on behalf of our subsidiary. After a bench trial held in January 2015, on February 5, 2015, the judge ruled that Formosa breached certain of its obligations under the gas processing and sales contract and that our subsidiary breached an obligation under each of the gas processing and sales contract and the related residue gas agreement. The amount of damages awarded to our subsidiary was in excess of the damages awarded to Formosa. However, the ultimate amount to be recovered by our subsidiary will not be finalized until the judge awards attorneys’ fees, if any. Until that issue is resolved, a judgment will not be entered and, as a result, we do not know the ultimate financial outcome of the lawsuit. Regardless of the attorneys’ fee issue, the judgment is not expected to have a material impact on our results of operations, cash flows or financial condition. We currently expect a final judgment to be entered in the second quarter of 2015, which may be appealed. 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. 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 classified as capital leases. The termination dates of the lease agreements vary from 2014 to 2018. We recorded amortization expense related to the capital leases of $0.6 million and $0.5 million for the year ended December 31, 2014 and 2013, respectively. Capital leases entered into during the year ended December 31, 2014 and 2013 were $0.7 million and $1.4 million , respectively. The capital lease obligation amounts included on the balance sheets were as follows (in thousands): December 31, 2014 December 31, 2013 Other current liabilities $ 455 $ 481 Other non-current liabilities 578 427 Total $ 1,033 $ 908 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 2014 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 , $1.5 million and $2.2 million for the years ended December 31, 2014, 2013 and 2012, respectively. Future Minimum Lease Payments Future minimum annual rental commitments under our capital and operating leases at December 31, 2014 were as follows (in thousands): Years Ending December 31, Capital Leases Operating Leases 2015 $ 468 $ 1,170 2016 283 1,156 2017 212 1,122 2018 95 1,055 2019 3 1,080 Thereafter — $ 5,775 Total future payments 1,061 $ 11,358 Less: Imputed interest $ (35 ) Future lease payments $ 1,026 Purchase Commitments At December 31, 2014, we had commitments of approximately $17.9 million for purchases of material and equipment related to our capital projects, primarily the construction of the Webb Pipeline. We have other planned capital projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.

TRANSACTIONS WITH RELATED PARTI

TRANSACTIONS WITH RELATED PARTIES	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Related Party Transactions [Abstract]
TRANSACTIONS WITH RELATED PARTIES	TRANSACTIONS WITH RELATED PARTIES Charlesbank, EIG & Tailwater (our Sponsors) Effective August 4, 2014, in connection with the Contribution and as a result of the Holdings Transaction, the board of directors of our General Partner includes one director affiliated with Charlesbank, one director affiliated with EIG, one director affiliated with Tailwater and three outside directors. The seventh member of the board of directors of our General Partner and its chairman, David W. Biegler, was selected by a majority of the other directors. Mr. Biegler will serve as the chairman from August 2014 for two years or until his earlier death or resignation. Our non-employee directors are reimbursed for certain expenses incurred for their services to us. The director services fees and expenses are included in general and administrative expenses in our statements of operations. We incurred fees and expenses related to the services from our affiliated directors as follows (in thousands): Three Months Ended March 31, 2015 2014 Charlesbank $ 14 $ — EIG 16 — Tailwater 16 — Total fees and expenses paid for director services to affiliated entities $ 46 $ — Southcross Energy Partners GP, LLC (our General Partner) Our General Partner does not receive a management fee or other compensation for its management of us. However, our General Partner and its affiliates are entitled to reimbursements for all expenses incurred on our behalf, including, among other items, compensation expense for all employees required to manage and operate our business. We incurred expenses related to these reimbursements as follows (in thousands): Three Months Ended March 31, 2015 2014 Reimbursements included in general and administrative expenses $ 3,134 $ 3,475 Reimbursements included in operations and maintenance expenses 4,781 3,943 Total reimbursements to our General Partner and its affiliates $ 7,915 $ 7,418 Compensation expense for services incurred by us on behalf of Southcross Energy LLC was billed to Southcross Energy LLC. For the three months ended March 31, 2015, compensation expense, which was not incurred on our behalf, of $0.1 million was billed to Southcross Energy LLC. No such amounts were incurred by us and billed to Southcross Energy LLC for the three months ended March 31, 2014. Wells Fargo Bank, N.A. Under our Senior Credit Facilities, Wells Fargo Bank, N.A. serves as the administrative agent (and served in that same capacity under our Previous Credit Facility). See Note 6. An affiliate of Wells Fargo Bank, N.A. is a member of our investor group. We entered into amendments to our Previous Credit Facility during 2013 and 2014. In addition, in connection with the TexStar Rich Gas System Transaction, during the third quarter of 2014, we entered into the Senior Credit Facilities, which include syndicates of financial institutions and other lenders. Affiliates of Wells Fargo Bank, N.A. have from time to time engaged in commercial banking and financial advisory transactions with us in the normal course of business. During the three months ended March 31, 2015 and 2014, we incurred costs, excluding interest, to Wells Fargo Bank, N.A. and its affiliates of $0.4 million and $0.2 million , respectively. Other Transactions with Affiliates Under the Distribution Agreement, we made customary representations, warranties and agreements, including an agreement to indemnify the Managers for certain liabilities under the Securities Act. The Managers and certain of their affiliates have engaged, and may in the future engage, in commercial and investment banking transactions with us in the ordinary course of their business for which they have received, and expect to receive, customary compensation and expense reimbursement. In particular, affiliates of each of the Managers are lenders under our Senior Credit Facilities, an affiliate of Wells Fargo Securities, LLC is a lender under our Senior Credit Facilities and affiliates of the other sales agents may from time to time hold positions under the Term Loan Agreement. If we use any net proceeds of this offering to repay borrowings under our Senior Credit Facilities, such affiliates of the Managers will receive proceeds of the offering. In conjunction with the TexStar Rich Gas System Transaction, we entered into 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 agreements, we transport, process and sell rich natural gas for the affiliate in return for fees that are substantially equivalent to the fees that Holdings receives from its customers for such services, and we can sell natural gas liquids that we own to Holdings at prices that are substantially equivalent to prices that Holdings receives from third parties. The NGL Agreement also permits us to utilize Holdings’ fractionation services at market-based rates. During the three months ended March 31, 2015, the Partnership recorded revenues from affiliates of $7.4 million in accordance with the G&P Agreement and the NGL Agreement. Accounts receivable due from affiliates of $8.9 million as of March 31, 2015 is comprised of primarily (a) $5.6 million due from TexStar, (b) $0.9 million due from Holdings relating to gathering and processing services in the period and (c) $1.3 million , $0.6 million and $0.1 million due from T2 Eagle Ford, T2 Cogen and T2 LaSalle (each as defined in Note 13), respectively, representing reimbursements for operating costs and equipment for this investment in the joint ventures. Accounts payable due to affiliates of $3.8 million as of March 31, 2015 is comprised of primarily (a) $1.4 million due to TexStar, and (b) $1.7 million , $0.5 million and $0.1 million due to T2 Cogen, T2 Eagle Ford and T2 LaSalle, respectively, representing operational obligations. In conjunction with the 2015 Holdings Acquisition, we entered into a series of commercial agreements with affiliates of Holdings including a gas gathering and treating agreement, a compression services agreement, a repair and maintenance agreement and an NGL transportation agreement. Under the terms of these commercial agreements, we gather, treat, transport, compress and redeliver natural gas for the affiliates of Holdings in return for agreed-upon fixed fees. In addition, under the NGL transportation agreement, we transport a minimum volume of NGLs per day at a fixed rate per gallon. The operational expense associated with such agreements has been capped at $1.7 million per quarter through December 31, 2016.	TRANSACTIONS WITH RELATED PARTIES Charlesbank, EIG & Tailwater (our Sponsors) For the year ended December 31, 2012, Southcross Energy LLC incurred management fees of $0.5 million for services received and incurred associated expenses of $68,000 under the Charlesbank Agreement (as defined below). Service fees and expenses under the Charlesbank Agreement were recognized in general and administrative expenses in our consolidated statements of operations. Subsequent to our IPO, we did not receive any further services under this agreement, as the Charlesbank Agreement terminated with our IPO. Therefore, no payments for services provided after that date were made under the Charlesbank Agreement. Effective August 4, 2014, in connection with the Contribution and as a result of the Holdings Transaction, the board of directors of our General Partner includes one director affiliated with Charlesbank, one director affiliated with EIG, one director affiliated with Tailwater and three outside directors. The seventh member of the board of directors of our General Partner and its chairman, David W. Biegler, was selected by a majority of the other directors. Mr. Biegler will serve as the chairman from August 2014 for two years or until his earlier death or resignation. Our non-employee directors are reimbursed for certain expenses incurred for their services to us. The director services fees and expenses are included in general and administrative expenses in our statements of operations. We incurred fees and expenses related to the services from our affiliated directors as follows (in thousands): Year Ended December 31, 2014 2013 2012 Charlesbank $ 340 $ 463 $ — EIG 20 — — Tailwater 20 — — Total fees and expenses paid for director services to affiliated entities $ 380 $ 463 $ — Southcross Energy LLC and Southcross Energy Partners GP, LLC Prior to our IPO in 2012, Charlesbank provided certain management services to Southcross Energy LLC pursuant to a management services agreement (the "Charlesbank Agreement") which specified an annual management fee of $0.6 million . Subsequent to our IPO, we did not receive any further services under this agreement, as the Charlesbank Agreement terminated with our IPO. As such, our General Partner no longer receives 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): Year Ended December 31, 2014 2013 2012 Reimbursements included in general and administrative expenses $ 10,944 $ 9,364 $ — Reimbursements included in operations and maintenance expenses 16,093 13,264 — Total reimbursements to our General Partner and its affiliates $ 27,037 $ 22,628 $ — Compensation expense for services incurred by us on behalf of Southcross Energy LLC was billed to Southcross Energy LLC. For the year ended December 31, 2014, compensation expense, which was not incurred on our behalf, of $0.9 million was billed to Southcross Energy LLC, $0.5 million of which is included in accounts receivable as of December 31, 2014. In December 2014, Southcross Energy LLC, on behalf of us, paid the settlement of the $1.2 million liability in connection with the accelerated vesting of the 15,000 outstanding equity equivalent units held by management due to the change in control provision triggered by the Holdings Transaction. See Note 14. We also provide management, administrative, operational and workforce related services to affiliated entities including Holdings, which owns 100% of our General Partner, and an affiliate that is jointly owned by EIG and Tailwater, two of our Sponsors. The expenses associated with these services, which are shared with these entities, are recorded in general and administrative expense in our statement of operations and are allocated in a manner approved by the board of directors and conflicts committee. During the year ended December 31, 2014, we allocated $1.0 million to Holdings, and $0.1 million to an affiliate of two of our Sponsors. In 2014, we paid approximately $2.8 million to Black Creek Well Services, LP, an entity in which two of our Sponsors (EIG and Tailwater) have an indirect controlling interest, for servicing work it performed for us. During the second quarter of 2013, we issued and sold 1,715,000 Series A Preferred Units to Southcross Energy LLC for a cash purchase price of $22.86 per Series A Preferred Unit, in a privately negotiated transaction (See Note 11). After the Series A Preferred Units issuance during the second quarter of 2013, Southcross Energy LLC sold 1,500,000 of the units to third parties. All of the Series A Preferred Units, including those held by Southcross Energy LLC, were converted into common units on August 4, 2014 in connection with the Holdings Transaction. See Notes 1 and 11. Wells Fargo Bank, N.A. Under our Senior Credit Facilities, Wells Fargo Bank, N.A. serves as the administrative agent (and served in that same capacity under our Previous Credit Facility). See Note 8. An affiliate of Wells Fargo Bank, N.A. is a member of our investor group. We entered into amendments to our Previous Credit Facility during 2013 and 2014. In addition, in connection with the TexStar Rich Gas System Transaction, during the third quarter of 2014, we entered into the Senior Credit Facilities, which include syndicates of financial institutions and other lenders. Affiliates of Wells Fargo Bank, N.A. have from time to time engaged in commercial banking and financial advisory transactions with us in the normal course of business. During the year ended December 31, 2014, 2013 and 2012, we incurred costs, excluding interest, to Wells Fargo Bank, N.A. and its affiliates of $9.5 million , $1.8 million and $5.9 million , respectively (See Notes 1 and 8). Other Transactions with Affiliates Under the Distribution Agreement, we made customary representations, warranties and agreements, including an agreement to indemnify the Managers for certain liabilities under the Securities Act. The Managers and certain of their affiliates have engaged, and may in the future engage, in commercial and investment banking transactions with us in the ordinary course of their business for which they have received, and expect to receive, customary compensation and expense reimbursement. In particular, affiliates of each of the Managers are lenders under our Senior Credit Facilities, an affiliate of Wells Fargo Securities, LLC is a lender under our Term Loan and affiliates of the other sales agents may from time to time hold positions in the Term Loan. If we use any net proceeds of this offering to repay borrowings under our Senior Credit Facilities, such affiliates of the Managers will receive proceeds of the offering. In conjunction with the TexStar Rich Gas System Transaction, we entered into 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 agreements, we transport, process and sell rich natural gas for the affiliate of Holdings in return for fees that are substantially equivalent to the fees that Holdings receives from its customers for such services, and we can sell natural gas liquids that we own to Holdings at prices that are substantially equivalent to prices that Holdings receives from third parties. In the future, when Holdings’ fractionation facility is operational, the NGL Agreement will permit us to utilize Holdings’ fractionation services at market-based rates. During the year ended December 31, 2014, the Partnership recorded revenues from affiliates of $13.3 million in accordance with the G&P Agreement and the NGL Agreement. Accounts receivable due from affiliates of $11.3 million as of December 31, 2014 is comprised of primarily (a) $5.8 million due from Holdings relating to gathering and processing services in the period and (b) $2.8 million and $2.3 million due from T2 Cogen (as defined in Note 16) and T2 La Salle Gas Utility LLC, a wholly owned subsidiary of T2 La Salle (as defined in Note 16), respectively representing reimbursements for operating costs and equipment for this investment in joint ventures. Accounts payable due to affiliates of $12.9 million as of December 31, 2014 is comprised of primarily (a) $5.4 million due to Holdings relating to reimbursements of insurance and capital costs and (b) $4.6 million due to T2 Cogen, T2 Gas Utility LLC, and T2 LaSalle Gas Utility LLC representing operational obligations. In conjunction with the 2015 Holdings Acquisition, we entered into a series of commercial agreements with affiliates of Holdings including a gas gathering and treating agreement, a compression services agreement, a repair and maintenance agreement and an NGL transportation agreement. Under the terms of these commercial agreements, we gather, treat, transport, compress and redeliver natural gas for the affiliates of Holdings in return for agreed-upon fixed fees. In addition, under the NGL transportation agreement, we transport a minimum volume of NGLs per day at a fixed rate per gallon. The operational expense associated with such agreements has been capped at $1.7 million per quarter through December 31, 2016.

SERIES A CONVERTIBLE PREFERRED

SERIES A CONVERTIBLE PREFERRED UNITS SERIES A CONVERTIBLE PREFERRED UNITS	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Statement of Partners' Capital [Abstract]
SERIES A CONVERTIBLE PREFERRED UNITS	SERIES A PREFERRED UNITS During the second quarter of 2013, we entered into a Series A Convertible Preferred Unit Purchase Agreement (the “Purchase Agreement”) with Southcross Energy LLC, pursuant to which we issued and sold 1,715,000 Series A Preferred Units to Southcross Energy LLC for a cash purchase price of $22.86 per unit, in a privately negotiated transaction (the “Private Placement”). Southcross Energy LLC sold 1,500,000 of these Series A Preferred Units to third parties during the second quarter of 2013. All of the Series A Preferred Units, including units held by Southcross Energy LLC, were converted to common units on August 4, 2014 in connection with the Holdings Transaction. See Notes 1 and 9. PARTNERS’ CAPITAL Ownership Our units outstanding as of March 31, 2015 are as follows (in units): Owned by Parent Partners’ Capital Public Class B General Common Common Convertible Subordinated Partner Units outstanding as of December 31, 2014 21,684,543 2,116,400 14,889,078 12,213,713 1,038,852 In-kind distributions and general partner issuances to maintain 2.0% ownership — — 260,558 — 5,318 Units outstanding as of March 31, 2015 21,684,543 2,116,400 15,149,636 12,213,713 1,044,170 Common Units Our common units represent limited partner interests in us. The holders of our common units are entitled to participate in partnership distributions and are entitled to exercise the rights and privileges available to limited partners under our Partnership Agreement. In February 2014, we completed a public equity offering of 9,200,000 additional common units and we received a capital contribution from our General Partner to maintain its 2.0% interest in us. The proceeds from the public offering were $144.7 million before estimated expenses related to the offering of $0.4 million . The net proceeds from the offering were used for our Onyx acquisition in March 2014, to fund the construction of our pipeline system extending into Webb County, Texas and for general partnership purposes. In connection with the TexStar Rich Gas System Transaction and the Holdings Transaction on August 4, 2014, we issued Class B Convertible Units, accelerated the vesting of awards under our LTIP (see Note 11), and all of the holders of our Series A Preferred Units elected to convert their Series A Preferred Units into common units based on an exchange ratio of 110%. Class B Convertible Units In connection with the TexStar Rich Gas System Transaction, on August 4, 2014, we established our Class B Convertible Units. The Class B Convertible Units consist of 14,633,000 of such 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. Our Partnership Agreement provides that we will procure the listing of the common units issuable upon conversion of the Class B Convertible Units on the New York Stock Exchange or other applicable national securities exchange. Distribution Rights: Commencing with the third quarter of 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 Class B Convertible Units. In connection with future distributions of Class B PIK Units, the General Partner is entitled to a corresponding distribution to maintain its 2.0% general partner interest in us. Conversion Rights: The Class B Convertible Units are convertible into common units on a one-for-one basis and, once converted, will participate in cash distributions pari passu with all other common units. The conversion of Class B Convertible Units will occur on the date we (a) make a quarterly distribution equal to or greater than $0.44 per common unit, (b) generate Class B Distributable Cash Flow (as defined in our Partnership Agreement) in an amount sufficient to pay the declared distribution on all units for the two quarters immediately preceding the date of conversion (the “measurement period”) and (c) forecast paying a distribution equal to or greater than $0.44 per unit from forecasted Class B Distributable Cash Flow on all outstanding common units for the two quarters immediately following the measurement period. Voting Rights: The Class B Convertible Units generally have the same voting rights as common units, and have one vote for each common unit into which such units are convertible. Changes in Partners’ Capital due to Holdings Transaction As discussed in Note 1, on August 4, 2014, Southcross Energy LLC and TexStar combined. As a result of this transaction, Holdings, through a wholly-owned subsidiary, (a) acquired 100% of TexStar and its general partner from BBTS Borrower LP and (b) acquired 2,116,400 of our common units and 12,213,713 of our subordinated units from Southcross Energy LLC. Thus, as a result of that transaction, Holdings acquired an approximate 57.4% limited partner interest in us, as well as 100% of our General Partner, which owns an approximate 2.0% interest in us and our incentive distribution rights. BBTS Borrower LP is controlled by EIG and Tailwater. In December 2014, BBTS Borrower LP distributed to each of EIG and Tailwater, in relatively equal proportions, its interest in Holdings. Southcross Energy LLC is controlled by Charlesbank. The Holdings Transaction resulted in our Sponsors each indirectly owning approximately one-third of Holdings. Affiliates of Energy Capital Partners Mezzanine Opportunities Fund and GE Energy Financial Services also own certain additional equity interests in Holdings. 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 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 . With respect to the fourth quarter of 2014, Holdings also waived the requirement that any distribution owed to it for that quarter be paid within 45 days of the end of the quarter, provided that the distribution was paid before or in conjunction with the filing of our 2014 Annual Report on Form 10-K. We paid a distribution of $0.28 per unit on our 12,213,713 subordinated units in conjunction with the filing of our 2014 Annual Report on Form 10-K. General Partner Interests As defined by the 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 from our general partner units purchased in connection with the Private Placement (see Note 8) and the Class B Convertible Units. In connection with other equity issuances, including issuances related to the TexStar Rich Gas System Transaction and the Holdings Transaction, our General Partner has made capital contributions in exchange for an issuance of additional general partner units to maintain its 2.0% ownership interest in us. Also, the General Partner has received general partner unit PIK distributions from the general partner units purchased in connection with the Private Placement (see Note 8). Equity Distribution Agreement On November 12, 2014, we established a $75 million "at-the-market" equity offering program pursuant to an equity distribution agreement (the “Distribution Agreement”) with Wells Fargo Securities, LLC, J.P. Morgan Securities LLC and RBC Capital Markets, LLC (each, a “Manager” and, collectively, the “Managers”). Under the Distribution Agreement, we may offer and sell up to $75 million in aggregate gross sales proceeds of our common units (the “Offered Units”) from time to time through the Managers, each as our sales agent. Sales of the Offered Units, if any, made under the Distribution Agreement will be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices prevailing at the time of sale in block transactions, or as otherwise agreed upon by us and any Manager. The Offered Units have been registered under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Registration No. 333-192105 declared effective December 10, 2013 (the "Registration Statement"), including the prospectus contained therein, as supplemented by the prospectus supplement filed with the SEC on November 12, 2014. We intend to use the net proceeds from the sale of the Offered Units for general partnership purposes, including the repayment of debt, acquisitions and funding capital expenditures. The Distribution Agreement contains customary representations, warranties and agreements by us, including our obligations to indemnify the Managers for certain liabilities under the Securities Act. The Managers and certain of their affiliates have engaged, and may in the future engage, in commercial and investment banking transactions with us in the ordinary course of their business for which they have received, and expect to receive, customary compensation and expense reimbursement. In particular, affiliates of each of the Managers are lenders under our Senior Credit Facilities, an affiliate of Wells Fargo Securities, LLC is a lender under our Term Loan Agreement, and affiliates of the other sales agents may from time to time hold positions under the Term Loan Agreement. If we use any net proceeds of this offering to repay borrowings under our Senior Credit Facilities, such affiliates of the Managers will receive proceeds of the offering. Holdings’ Equity in Contributed Subsidiaries Holdings’ equity in contributed subsidiaries represents its position in the net assets of the 2015 Holdings Acquisition as of March 31, 2015 that have been acquired by the Partnership. 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). As such, the equity balance also reflects net income attributable to the 2015 Holdings Acquisition for all periods ending after August 4, 2014. Net income was attributed to the Partnership for the 2015 Holdings Acquisition for the three months period ended March 31, 2015. Although included in partners' capital, net income attributable to the 2015 Holdings Acquisition has been excluded from the calculation of earnings per unit and presented separately as net loss attributable to Holdings. See Notes 1 and 2.	SERIES A CONVERTIBLE PREFERRED UNITS We entered into a Series A Convertible Preferred Unit Purchase Agreement (the “Purchase Agreement”) with Southcross Energy LLC, pursuant to which we issued and sold 1,715,000 Series A Preferred Units to Southcross Energy LLC during the second quarter of 2013 for a cash purchase price of $22.86 per unit, in a privately negotiated transaction (the "Private Placement"). Southcross Energy LLC sold 1,500,000 of these Series A Preferred Units to third parties during the second quarter of 2013. The Private Placement of Series A Preferred Units resulted in proceeds to us of $39.2 million . We also received a $0.8 million capital contribution from our General Partner to maintain its 2.0% general partner interest in us. Our total capital infusion of $40.0 million , from all sales of Series A Preferred Units and General Partner capital contributions, was used to reduce borrowings under our Previous Credit Facility (See Note 8). All of the Series A Preferred Units, including units held by Southcross Energy LLC, were converted to common units on August 4, 2014 in connection with the Holdings Transaction. See Note 1 and below. Because the Series A Preferred Units were equity instruments and redeemable at the option of the holder, they were classified outside of permanent equity. The change of control rights associated with the Series A Preferred Units required the units to be classified outside of permanent equity. The Series A Preferred Units were periodically adjusted to maximum redemption value because maximum redemption value was different than the fair value of the unit at the issuance date. Voting Rights: The Series A Preferred Units were a class of voting equity security that rank senior to all of our other classes or series of equity securities with respect to distribution rights and rights upon liquidation. The Series A Preferred Units had voting rights identical to the voting rights of the common units and voted with the common units as a single class, such that each Series A Preferred Unit (including each Series A Preferred Unit issued as an in-kind distribution, discussed below) was entitled to one vote for each common unit into which such Series A Preferred Unit was convertible on each matter with respect to which each common unit was entitled to vote. Distribution Rights: Holders of Series A Preferred Units were entitled to quarterly distributions of in-kind Series A Preferred Units for the first four full quarters following the issue date of those units and continuing thereafter until the board of directors of our General Partner determined to begin paying quarterly distributions in cash, and thereafter in cash. In-kind distributions were in the form of Series A Preferred Units at a rate of $0.40 per outstanding Series A Preferred Unit per quarter (or 7% per year of the per unit purchase price). Cash distributions equaled the greater of $0.40 per unit per quarter or the quarterly distribution paid with respect to each common unit. Conversion Rights: The Series A Preferred Units were convertible into common units based on an exchange ratio of 110% of the Series A Preferred Units in certain circumstances before January 1, 2015. In connection with the Holdings Transaction and pursuant to the change in control provision in our partnership agreement applicable to our Series A Preferred Units, all holders of the Series A Preferred Units elected to convert their Series A Preferred Units into 2,015,638 common units based on the 110% exchange ratio. Dissolution and Liquidation: The Series A Preferred Units were senior to our common units with respect to rights on dissolution and liquidation. Common units issued upon conversion of the Series A Preferred Units have equal ranking with the rest of our common units with respect to rights on dissolution and liquidation. PARTNERS' CAPITAL AND MEMBERS' EQUITY Ownership Our units outstanding as of December 31, 2014 are as follows (in units): Partners’ Capital Owned By Parent Series A Public Holdings Class B General Preferred Common Common Convertible Subordinated Partner Units outstanding as of December 31, 2013 1,769,915 10,390,272 — — 12,213,713 534,638 Issuance of common units — 9,200,000 — — — 187,755 Holdings Transaction — — 1,863,713 — — — Series A Convertible preferred conversion to common units (1,832,399 ) 1,762,951 252,687 — — — Issuance of Class B Convertible Units — — — 14,633,000 — — Vesting of LTIP units, net — 331,320 — — — — In-kind distributions and general partner issuances to maintain 2.0% ownership 62,484 — — 256,078 — 316,459 Units outstanding as of December 31, 2014 — 21,684,543 2,116,400 14,889,078 12,213,713 1,038,852 On November 7, 2012, we completed our IPO. Through a series of transactions, Southcross Energy LLC contributed all of its operating subsidiaries (its net assets on a historical cost basis), excluding certain liabilities and all preferred units, and became the holding company of us. Until the Holdings Transaction, Southcross Energy LLC held all of the equity interests in our General Partner, as well as all subordinated units and a portion of the common units and Series A Preferred Units of us. Subsequent to our IPO, we own Southcross Energy LLC's operating subsidiaries. At the completion of our IPO, we received proceeds of approximately $168.0 million , net of underwriters' discounts and structuring fees. In connection with the full exercise of the underwriter's over-allotment option, which closed on November 26, 2012, our underwriters purchased 1,350,000 additional common units in us for approximately $25.2 million in proceeds, net of underwriters' and structuring fees; and we used the net proceeds of $25.2 million to reacquire 1,350,000 common units from Southcross Energy LLC and retired the common units. On November 29, 2013, we filed a Registration Statement on Form S-3 with the SEC using a "shelf" registration process. Under the shelf registration process, we may over time, in one or more offerings, offer and sell any combination of the securities described in the prospectus, and the selling unitholders may, over time, in one or more offerings, offer and sell common units representing limited partner interests in us. We, together with Southcross Energy Finance Corp., may offer and sell debt securities described in the prospectus. Southcross Energy Finance Corp. may act as co-issuer of the debt securities, and certain direct or indirect subsidiaries of us may guarantee any debt securities offered, if and to the extent identified in the related prospectus supplement. The aggregate initial offering price of all securities sold by us under the prospectus will not exceed $675.0 million . 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 February 2014, we completed a public equity offering of 9,200,000 additional common units and we received a capital contribution from our General Partner to maintain its 2.0% interest in us. The proceeds from the public offering were $144.7 million , before estimated expenses related to the offering of $0.4 million . The net proceeds from the offering were used for our Onyx acquisition in March 2014, to fund the construction of our Webb Pipeline and for general partnership purposes. In connection with the TexStar Rich Gas System Transaction and the Holdings Transaction on August 4, 2014, we issued Class B Convertible Units, accelerated the vesting of awards under our LTIP, and all of the holders of our Series A Preferred Units elected to convert their Series A Preferred Units into common units based on an exchange ratio of 110% . Class B Convertible Units In connection with the Contribution, on August 4, 2014, we established our Class B Convertible Units. The Class B Convertible Units consist of 14,633,000 of such 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. Our Partnership Agreement provides that we will procure the listing of the common units issuable upon conversion of the Class B Convertible Units on the New York Stock Exchange or other applicable national securities exchange. Distribution Rights: Commencing with the third quarter of 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 Class B Convertible Units. In connection with future distributions of Class B PIK Units, the General Partner is entitled to a corresponding distribution to maintain its 2.0% general partner interest in us. Conversion Rights: The Class B Convertible Units are convertible into common units on a one-for-one basis and, once converted, will participate in cash distributions pari passu with all other common units. The conversion of Class B Convertible Units will occur on the date we (a) make a quarterly distribution equal to or greater than $0.44 per common unit, (b) generate Class B Distributable Cash Flow (as defined in our Partnership Agreement) in an amount sufficient to pay the declared distribution on all units for the two quarters immediately preceding the date of conversion (the “measurement period”) and (c) forecast paying a distribution equal to or greater than $0.44 per unit from forecasted Class B Distributable Cash Flow on all outstanding common units for the two quarters immediately following the measurement period. Voting Rights: The Class B Convertible Units generally have the same voting rights as common units, and have one vote for each common unit into which such units are convertible. Changes in Partners’ Capital due to Holdings Transaction As discussed in Note 1, on August 4, 2014, Southcross Energy LLC and TexStar combined. As a result of this transaction, Holdings, through a wholly-owned subsidiary, (a) acquired 100% of TexStar and its general partner from BBTS Borrower LP and (b) acquired 2,116,400 of our common units and 12,213,713 of our subordinated units from Southcross Energy LLC. Thus, as a result of that transaction, Holdings acquired an approximate 57.4% limited partner interest in us, as well as 100% of our General Partner, which owns an approximate 2.0% interest in us and our incentive distribution rights. BBTS Borrower LP is controlled by EIG and Tailwater. In November 2014, BBTS Borrower LP distributed to each of EIG and Tailwater, in relatively equal proportions, its interest in Holdings. Southcross Energy LLC is controlled by Charlesbank. The Holdings Transaction resulted in the Sponsors each indirectly owning approximately one-third of Holdings. Affiliates of Energy Capital Partners Mezzanine Opportunities Fund and GE Energy Financial Services own certain additional ownership interests in Holdings as well. 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 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 . With respect to the fourth quarter of 2014, Holdings waived the requirement that any distribution owed to it for that quarter be paid within 45 days of the end of the quarter, provided that the distribution is paid before or in conjunction with the filing of this Form 10-K. General Partner Interests As defined by the 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 from our general partner units purchased in connection with the sale of the Series A Preferred Units (See Note 11) and the Class B Convertible Units. In connection with other equity issuances, including issuances related to the TexStar Rich Gas System Transaction and the Holdings Transaction, our General Partner has made capital contributions in exchange for an issuance of additional general partner units to maintain its 2.0% ownership interest in us. Also, the General Partner has received general partner unit PIK distributions from the general partner units purchased in connection with the Private Placement (See Note 11). Equity Distribution Agreement On November 12, 2014, we established a $75 million "at-the-market" equity offering program pursuant to an equity distribution agreement (the “Distribution Agreement”) with Wells Fargo Securities, LLC, J.P. Morgan Securities LLC and RBC Capital Markets, LLC (each, a “Manager” and, collectively, the “Managers”). Under the Distribution Agreement, we may offer and sell up to $75 million in aggregate gross sales proceeds of our common units (the “Offered Units”) from time to time through the Managers, each as our sales agent. Sales of the Offered Units, if any, made under the Distribution Agreement will be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices prevailing at the time of sale in block transactions, or as otherwise agreed upon by us and any Manager. The Offered Units have been registered under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Registration No. 333-192105, declared effective December 10, 2013, (the "Registration Statement"), including the prospectus contained therein, as supplemented by the prospectus supplement filed with the SEC on November 12, 2014. We intend to use the net proceeds from the sale of the Offered Units for general partnership purposes, including the repayment of debt, acquisitions and funding capital expenditures. The Distribution Agreement contains customary representations, warranties and agreements by us, including our obligations to indemnify the Managers for certain liabilities under the Securities Act. The Managers and certain of their affiliates have engaged, and may in the future engage, in commercial and investment banking transactions with us in the ordinary course of their business for which they have received, and expect to receive, customary compensation and expense reimbursement. In particular, affiliates of each of the Managers are lenders under our Senior Credit Facilities, an affiliate of Wells Fargo Securities, LLC is a lender under our Term Loan and affiliates of the other sales agents may from time to time hold positions in the Term Loan. If we use any net proceeds of this offering to repay borrowings under our Senior Credit Facilities, such affiliates of the Managers will receive proceeds of the offering. Members' Equity of Southcross Energy LLC On August 6, 2009, five members of the Southcross Energy LLC's management team purchased, directly or indirectly through Estrella Energy, LP, Class A common units and Class B units along with Charlesbank, for the same value as Charlesbank, ( $1.00 per unit). Estrella Energy, LP was partially owned by a non-management third-party, and thus a portion of the time- and performance-based units ("Third-Party Units") owned by Estrella Energy, LP were owned indirectly by the non-management third-party. As of December 31, 2011, Southcross Energy LLC's common equity was comprised of 1,415,729 Class A authorized and outstanding common units, of which 217,483 were unvested, and 57,279 authorized and outstanding Class B units, of which 34,367 were unvested. The Class B units have the same distribution and liquidation rights as the Class A common units; however, they do not have voting rights. All Class A common units and Class B units were sold for, and have a par value of, $1.00 per unit. Certain of the Class A common units and all of the Class B units contain time- and performance-vesting conditions. Time-vesting units vest ratably over 5 years subject to certain accelerated vesting based primarily on change of control or certain termination causes. Performance-vesting units will vest, if at all, upon Charlesbank attaining certain investment multiples and internal rates of return in connection with a liquidity event. Both the time- and performance vesting units require continued employment through any vesting date. The change in structure and ownership as a result of our IPO did not create a change of control event under the terms of the time- and performance-vesting units. On March 20, 2012, Estrella Energy, LP was dissolved and Southcross Energy LLC purchased and retired the Third-Party Units for $15.3 million . Management did not receive any consideration in connection with such repurchase. Holdings’ Equity in Contributed Subsidiaries . Holdings’ equity in contributed subsidiaries represents its position in the net assets of the 2015 Holdings Acquisition as of December 31, 2014 that have been acquired by the Partnership. 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). As such, the equity balance also reflects net income attributable to the 2015 Holdings Acquisition for all periods ending after August 4, 2014. During the year ended December 31, 2014, net income was attributed to the Partnership for the 2015 Holdings Acquisition for the period from August 4, 2014 to December 31, 2014. Although included in partners' capital, net income attributable to the 2015 Holdings Acquisition has been excluded from the calculation of earnings per unit and presented separately as net loss attributable to Holdings. See Notes 1, 3 and 5.

PARTNERS' CAPITAL AND MEMBERS'

PARTNERS' CAPITAL AND MEMBERS' EQUITY	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Partners' Capital Notes [Abstract]
PARTNERS' CAPITAL AND MEMBERS' EQUITY	SERIES A PREFERRED UNITS During the second quarter of 2013, we entered into a Series A Convertible Preferred Unit Purchase Agreement (the “Purchase Agreement”) with Southcross Energy LLC, pursuant to which we issued and sold 1,715,000 Series A Preferred Units to Southcross Energy LLC for a cash purchase price of $22.86 per unit, in a privately negotiated transaction (the “Private Placement”). Southcross Energy LLC sold 1,500,000 of these Series A Preferred Units to third parties during the second quarter of 2013. All of the Series A Preferred Units, including units held by Southcross Energy LLC, were converted to common units on August 4, 2014 in connection with the Holdings Transaction. See Notes 1 and 9. PARTNERS’ CAPITAL Ownership Our units outstanding as of March 31, 2015 are as follows (in units): Owned by Parent Partners’ Capital Public Class B General Common Common Convertible Subordinated Partner Units outstanding as of December 31, 2014 21,684,543 2,116,400 14,889,078 12,213,713 1,038,852 In-kind distributions and general partner issuances to maintain 2.0% ownership — — 260,558 — 5,318 Units outstanding as of March 31, 2015 21,684,543 2,116,400 15,149,636 12,213,713 1,044,170 Common Units Our common units represent limited partner interests in us. The holders of our common units are entitled to participate in partnership distributions and are entitled to exercise the rights and privileges available to limited partners under our Partnership Agreement. In February 2014, we completed a public equity offering of 9,200,000 additional common units and we received a capital contribution from our General Partner to maintain its 2.0% interest in us. The proceeds from the public offering were $144.7 million before estimated expenses related to the offering of $0.4 million . The net proceeds from the offering were used for our Onyx acquisition in March 2014, to fund the construction of our pipeline system extending into Webb County, Texas and for general partnership purposes. In connection with the TexStar Rich Gas System Transaction and the Holdings Transaction on August 4, 2014, we issued Class B Convertible Units, accelerated the vesting of awards under our LTIP (see Note 11), and all of the holders of our Series A Preferred Units elected to convert their Series A Preferred Units into common units based on an exchange ratio of 110%. Class B Convertible Units In connection with the TexStar Rich Gas System Transaction, on August 4, 2014, we established our Class B Convertible Units. The Class B Convertible Units consist of 14,633,000 of such 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. Our Partnership Agreement provides that we will procure the listing of the common units issuable upon conversion of the Class B Convertible Units on the New York Stock Exchange or other applicable national securities exchange. Distribution Rights: Commencing with the third quarter of 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 Class B Convertible Units. In connection with future distributions of Class B PIK Units, the General Partner is entitled to a corresponding distribution to maintain its 2.0% general partner interest in us. Conversion Rights: The Class B Convertible Units are convertible into common units on a one-for-one basis and, once converted, will participate in cash distributions pari passu with all other common units. The conversion of Class B Convertible Units will occur on the date we (a) make a quarterly distribution equal to or greater than $0.44 per common unit, (b) generate Class B Distributable Cash Flow (as defined in our Partnership Agreement) in an amount sufficient to pay the declared distribution on all units for the two quarters immediately preceding the date of conversion (the “measurement period”) and (c) forecast paying a distribution equal to or greater than $0.44 per unit from forecasted Class B Distributable Cash Flow on all outstanding common units for the two quarters immediately following the measurement period. Voting Rights: The Class B Convertible Units generally have the same voting rights as common units, and have one vote for each common unit into which such units are convertible. Changes in Partners’ Capital due to Holdings Transaction As discussed in Note 1, on August 4, 2014, Southcross Energy LLC and TexStar combined. As a result of this transaction, Holdings, through a wholly-owned subsidiary, (a) acquired 100% of TexStar and its general partner from BBTS Borrower LP and (b) acquired 2,116,400 of our common units and 12,213,713 of our subordinated units from Southcross Energy LLC. Thus, as a result of that transaction, Holdings acquired an approximate 57.4% limited partner interest in us, as well as 100% of our General Partner, which owns an approximate 2.0% interest in us and our incentive distribution rights. BBTS Borrower LP is controlled by EIG and Tailwater. In December 2014, BBTS Borrower LP distributed to each of EIG and Tailwater, in relatively equal proportions, its interest in Holdings. Southcross Energy LLC is controlled by Charlesbank. The Holdings Transaction resulted in our Sponsors each indirectly owning approximately one-third of Holdings. Affiliates of Energy Capital Partners Mezzanine Opportunities Fund and GE Energy Financial Services also own certain additional equity interests in Holdings. 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 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 . With respect to the fourth quarter of 2014, Holdings also waived the requirement that any distribution owed to it for that quarter be paid within 45 days of the end of the quarter, provided that the distribution was paid before or in conjunction with the filing of our 2014 Annual Report on Form 10-K. We paid a distribution of $0.28 per unit on our 12,213,713 subordinated units in conjunction with the filing of our 2014 Annual Report on Form 10-K. General Partner Interests As defined by the 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 from our general partner units purchased in connection with the Private Placement (see Note 8) and the Class B Convertible Units. In connection with other equity issuances, including issuances related to the TexStar Rich Gas System Transaction and the Holdings Transaction, our General Partner has made capital contributions in exchange for an issuance of additional general partner units to maintain its 2.0% ownership interest in us. Also, the General Partner has received general partner unit PIK distributions from the general partner units purchased in connection with the Private Placement (see Note 8). Equity Distribution Agreement On November 12, 2014, we established a $75 million "at-the-market" equity offering program pursuant to an equity distribution agreement (the “Distribution Agreement”) with Wells Fargo Securities, LLC, J.P. Morgan Securities LLC and RBC Capital Markets, LLC (each, a “Manager” and, collectively, the “Managers”). Under the Distribution Agreement, we may offer and sell up to $75 million in aggregate gross sales proceeds of our common units (the “Offered Units”) from time to time through the Managers, each as our sales agent. Sales of the Offered Units, if any, made under the Distribution Agreement will be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices prevailing at the time of sale in block transactions, or as otherwise agreed upon by us and any Manager. The Offered Units have been registered under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Registration No. 333-192105 declared effective December 10, 2013 (the "Registration Statement"), including the prospectus contained therein, as supplemented by the prospectus supplement filed with the SEC on November 12, 2014. We intend to use the net proceeds from the sale of the Offered Units for general partnership purposes, including the repayment of debt, acquisitions and funding capital expenditures. The Distribution Agreement contains customary representations, warranties and agreements by us, including our obligations to indemnify the Managers for certain liabilities under the Securities Act. The Managers and certain of their affiliates have engaged, and may in the future engage, in commercial and investment banking transactions with us in the ordinary course of their business for which they have received, and expect to receive, customary compensation and expense reimbursement. In particular, affiliates of each of the Managers are lenders under our Senior Credit Facilities, an affiliate of Wells Fargo Securities, LLC is a lender under our Term Loan Agreement, and affiliates of the other sales agents may from time to time hold positions under the Term Loan Agreement. If we use any net proceeds of this offering to repay borrowings under our Senior Credit Facilities, such affiliates of the Managers will receive proceeds of the offering. Holdings’ Equity in Contributed Subsidiaries Holdings’ equity in contributed subsidiaries represents its position in the net assets of the 2015 Holdings Acquisition as of March 31, 2015 that have been acquired by the Partnership. 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). As such, the equity balance also reflects net income attributable to the 2015 Holdings Acquisition for all periods ending after August 4, 2014. Net income was attributed to the Partnership for the 2015 Holdings Acquisition for the three months period ended March 31, 2015. Although included in partners' capital, net income attributable to the 2015 Holdings Acquisition has been excluded from the calculation of earnings per unit and presented separately as net loss attributable to Holdings. See Notes 1 and 2.	SERIES A CONVERTIBLE PREFERRED UNITS We entered into a Series A Convertible Preferred Unit Purchase Agreement (the “Purchase Agreement”) with Southcross Energy LLC, pursuant to which we issued and sold 1,715,000 Series A Preferred Units to Southcross Energy LLC during the second quarter of 2013 for a cash purchase price of $22.86 per unit, in a privately negotiated transaction (the "Private Placement"). Southcross Energy LLC sold 1,500,000 of these Series A Preferred Units to third parties during the second quarter of 2013. The Private Placement of Series A Preferred Units resulted in proceeds to us of $39.2 million . We also received a $0.8 million capital contribution from our General Partner to maintain its 2.0% general partner interest in us. Our total capital infusion of $40.0 million , from all sales of Series A Preferred Units and General Partner capital contributions, was used to reduce borrowings under our Previous Credit Facility (See Note 8). All of the Series A Preferred Units, including units held by Southcross Energy LLC, were converted to common units on August 4, 2014 in connection with the Holdings Transaction. See Note 1 and below. Because the Series A Preferred Units were equity instruments and redeemable at the option of the holder, they were classified outside of permanent equity. The change of control rights associated with the Series A Preferred Units required the units to be classified outside of permanent equity. The Series A Preferred Units were periodically adjusted to maximum redemption value because maximum redemption value was different than the fair value of the unit at the issuance date. Voting Rights: The Series A Preferred Units were a class of voting equity security that rank senior to all of our other classes or series of equity securities with respect to distribution rights and rights upon liquidation. The Series A Preferred Units had voting rights identical to the voting rights of the common units and voted with the common units as a single class, such that each Series A Preferred Unit (including each Series A Preferred Unit issued as an in-kind distribution, discussed below) was entitled to one vote for each common unit into which such Series A Preferred Unit was convertible on each matter with respect to which each common unit was entitled to vote. Distribution Rights: Holders of Series A Preferred Units were entitled to quarterly distributions of in-kind Series A Preferred Units for the first four full quarters following the issue date of those units and continuing thereafter until the board of directors of our General Partner determined to begin paying quarterly distributions in cash, and thereafter in cash. In-kind distributions were in the form of Series A Preferred Units at a rate of $0.40 per outstanding Series A Preferred Unit per quarter (or 7% per year of the per unit purchase price). Cash distributions equaled the greater of $0.40 per unit per quarter or the quarterly distribution paid with respect to each common unit. Conversion Rights: The Series A Preferred Units were convertible into common units based on an exchange ratio of 110% of the Series A Preferred Units in certain circumstances before January 1, 2015. In connection with the Holdings Transaction and pursuant to the change in control provision in our partnership agreement applicable to our Series A Preferred Units, all holders of the Series A Preferred Units elected to convert their Series A Preferred Units into 2,015,638 common units based on the 110% exchange ratio. Dissolution and Liquidation: The Series A Preferred Units were senior to our common units with respect to rights on dissolution and liquidation. Common units issued upon conversion of the Series A Preferred Units have equal ranking with the rest of our common units with respect to rights on dissolution and liquidation. PARTNERS' CAPITAL AND MEMBERS' EQUITY Ownership Our units outstanding as of December 31, 2014 are as follows (in units): Partners’ Capital Owned By Parent Series A Public Holdings Class B General Preferred Common Common Convertible Subordinated Partner Units outstanding as of December 31, 2013 1,769,915 10,390,272 — — 12,213,713 534,638 Issuance of common units — 9,200,000 — — — 187,755 Holdings Transaction — — 1,863,713 — — — Series A Convertible preferred conversion to common units (1,832,399 ) 1,762,951 252,687 — — — Issuance of Class B Convertible Units — — — 14,633,000 — — Vesting of LTIP units, net — 331,320 — — — — In-kind distributions and general partner issuances to maintain 2.0% ownership 62,484 — — 256,078 — 316,459 Units outstanding as of December 31, 2014 — 21,684,543 2,116,400 14,889,078 12,213,713 1,038,852 On November 7, 2012, we completed our IPO. Through a series of transactions, Southcross Energy LLC contributed all of its operating subsidiaries (its net assets on a historical cost basis), excluding certain liabilities and all preferred units, and became the holding company of us. Until the Holdings Transaction, Southcross Energy LLC held all of the equity interests in our General Partner, as well as all subordinated units and a portion of the common units and Series A Preferred Units of us. Subsequent to our IPO, we own Southcross Energy LLC's operating subsidiaries. At the completion of our IPO, we received proceeds of approximately $168.0 million , net of underwriters' discounts and structuring fees. In connection with the full exercise of the underwriter's over-allotment option, which closed on November 26, 2012, our underwriters purchased 1,350,000 additional common units in us for approximately $25.2 million in proceeds, net of underwriters' and structuring fees; and we used the net proceeds of $25.2 million to reacquire 1,350,000 common units from Southcross Energy LLC and retired the common units. On November 29, 2013, we filed a Registration Statement on Form S-3 with the SEC using a "shelf" registration process. Under the shelf registration process, we may over time, in one or more offerings, offer and sell any combination of the securities described in the prospectus, and the selling unitholders may, over time, in one or more offerings, offer and sell common units representing limited partner interests in us. We, together with Southcross Energy Finance Corp., may offer and sell debt securities described in the prospectus. Southcross Energy Finance Corp. may act as co-issuer of the debt securities, and certain direct or indirect subsidiaries of us may guarantee any debt securities offered, if and to the extent identified in the related prospectus supplement. The aggregate initial offering price of all securities sold by us under the prospectus will not exceed $675.0 million . 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 February 2014, we completed a public equity offering of 9,200,000 additional common units and we received a capital contribution from our General Partner to maintain its 2.0% interest in us. The proceeds from the public offering were $144.7 million , before estimated expenses related to the offering of $0.4 million . The net proceeds from the offering were used for our Onyx acquisition in March 2014, to fund the construction of our Webb Pipeline and for general partnership purposes. In connection with the TexStar Rich Gas System Transaction and the Holdings Transaction on August 4, 2014, we issued Class B Convertible Units, accelerated the vesting of awards under our LTIP, and all of the holders of our Series A Preferred Units elected to convert their Series A Preferred Units into common units based on an exchange ratio of 110% . Class B Convertible Units In connection with the Contribution, on August 4, 2014, we established our Class B Convertible Units. The Class B Convertible Units consist of 14,633,000 of such 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. Our Partnership Agreement provides that we will procure the listing of the common units issuable upon conversion of the Class B Convertible Units on the New York Stock Exchange or other applicable national securities exchange. Distribution Rights: Commencing with the third quarter of 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 Class B Convertible Units. In connection with future distributions of Class B PIK Units, the General Partner is entitled to a corresponding distribution to maintain its 2.0% general partner interest in us. Conversion Rights: The Class B Convertible Units are convertible into common units on a one-for-one basis and, once converted, will participate in cash distributions pari passu with all other common units. The conversion of Class B Convertible Units will occur on the date we (a) make a quarterly distribution equal to or greater than $0.44 per common unit, (b) generate Class B Distributable Cash Flow (as defined in our Partnership Agreement) in an amount sufficient to pay the declared distribution on all units for the two quarters immediately preceding the date of conversion (the “measurement period”) and (c) forecast paying a distribution equal to or greater than $0.44 per unit from forecasted Class B Distributable Cash Flow on all outstanding common units for the two quarters immediately following the measurement period. Voting Rights: The Class B Convertible Units generally have the same voting rights as common units, and have one vote for each common unit into which such units are convertible. Changes in Partners’ Capital due to Holdings Transaction As discussed in Note 1, on August 4, 2014, Southcross Energy LLC and TexStar combined. As a result of this transaction, Holdings, through a wholly-owned subsidiary, (a) acquired 100% of TexStar and its general partner from BBTS Borrower LP and (b) acquired 2,116,400 of our common units and 12,213,713 of our subordinated units from Southcross Energy LLC. Thus, as a result of that transaction, Holdings acquired an approximate 57.4% limited partner interest in us, as well as 100% of our General Partner, which owns an approximate 2.0% interest in us and our incentive distribution rights. BBTS Borrower LP is controlled by EIG and Tailwater. In November 2014, BBTS Borrower LP distributed to each of EIG and Tailwater, in relatively equal proportions, its interest in Holdings. Southcross Energy LLC is controlled by Charlesbank. The Holdings Transaction resulted in the Sponsors each indirectly owning approximately one-third of Holdings. Affiliates of Energy Capital Partners Mezzanine Opportunities Fund and GE Energy Financial Services own certain additional ownership interests in Holdings as well. 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 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 . With respect to the fourth quarter of 2014, Holdings waived the requirement that any distribution owed to it for that quarter be paid within 45 days of the end of the quarter, provided that the distribution is paid before or in conjunction with the filing of this Form 10-K. General Partner Interests As defined by the 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 from our general partner units purchased in connection with the sale of the Series A Preferred Units (See Note 11) and the Class B Convertible Units. In connection with other equity issuances, including issuances related to the TexStar Rich Gas System Transaction and the Holdings Transaction, our General Partner has made capital contributions in exchange for an issuance of additional general partner units to maintain its 2.0% ownership interest in us. Also, the General Partner has received general partner unit PIK distributions from the general partner units purchased in connection with the Private Placement (See Note 11). Equity Distribution Agreement On November 12, 2014, we established a $75 million "at-the-market" equity offering program pursuant to an equity distribution agreement (the “Distribution Agreement”) with Wells Fargo Securities, LLC, J.P. Morgan Securities LLC and RBC Capital Markets, LLC (each, a “Manager” and, collectively, the “Managers”). Under the Distribution Agreement, we may offer and sell up to $75 million in aggregate gross sales proceeds of our common units (the “Offered Units”) from time to time through the Managers, each as our sales agent. Sales of the Offered Units, if any, made under the Distribution Agreement will be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices prevailing at the time of sale in block transactions, or as otherwise agreed upon by us and any Manager. The Offered Units have been registered under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Registration No. 333-192105, declared effective December 10, 2013, (the "Registration Statement"), including the prospectus contained therein, as supplemented by the prospectus supplement filed with the SEC on November 12, 2014. We intend to use the net proceeds from the sale of the Offered Units for general partnership purposes, including the repayment of debt, acquisitions and funding capital expenditures. The Distribution Agreement contains customary representations, warranties and agreements by us, including our obligations to indemnify the Managers for certain liabilities under the Securities Act. The Managers and certain of their affiliates have engaged, and may in the future engage, in commercial and investment banking transactions with us in the ordinary course of their business for which they have received, and expect to receive, customary compensation and expense reimbursement. In particular, affiliates of each of the Managers are lenders under our Senior Credit Facilities, an affiliate of Wells Fargo Securities, LLC is a lender under our Term Loan and affiliates of the other sales agents may from time to time hold positions in the Term Loan. If we use any net proceeds of this offering to repay borrowings under our Senior Credit Facilities, such affiliates of the Managers will receive proceeds of the offering. Members' Equity of Southcross Energy LLC On August 6, 2009, five members of the Southcross Energy LLC's management team purchased, directly or indirectly through Estrella Energy, LP, Class A common units and Class B units along with Charlesbank, for the same value as Charlesbank, ( $1.00 per unit). Estrella Energy, LP was partially owned by a non-management third-party, and thus a portion of the time- and performance-based units ("Third-Party Units") owned by Estrella Energy, LP were owned indirectly by the non-management third-party. As of December 31, 2011, Southcross Energy LLC's common equity was comprised of 1,415,729 Class A authorized and outstanding common units, of which 217,483 were unvested, and 57,279 authorized and outstanding Class B units, of which 34,367 were unvested. The Class B units have the same distribution and liquidation rights as the Class A common units; however, they do not have voting rights. All Class A common units and Class B units were sold for, and have a par value of, $1.00 per unit. Certain of the Class A common units and all of the Class B units contain time- and performance-vesting conditions. Time-vesting units vest ratably over 5 years subject to certain accelerated vesting based primarily on change of control or certain termination causes. Performance-vesting units will vest, if at all, upon Charlesbank attaining certain investment multiples and internal rates of return in connection with a liquidity event. Both the time- and performance vesting units require continued employment through any vesting date. The change in structure and ownership as a result of our IPO did not create a change of control event under the terms of the time- and performance-vesting units. On March 20, 2012, Estrella Energy, LP was dissolved and Southcross Energy LLC purchased and retired the Third-Party Units for $15.3 million . Management did not receive any consideration in connection with such repurchase. Holdings’ Equity in Contributed Subsidiaries . Holdings’ equity in contributed subsidiaries represents its position in the net assets of the 2015 Holdings Acquisition as of December 31, 2014 that have been acquired by the Partnership. 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). As such, the equity balance also reflects net income attributable to the 2015 Holdings Acquisition for all periods ending after August 4, 2014. During the year ended December 31, 2014, net income was attributed to the Partnership for the 2015 Holdings Acquisition for the period from August 4, 2014 to December 31, 2014. Although included in partners' capital, net income attributable to the 2015 Holdings Acquisition has been excluded from the calculation of earnings per unit and presented separately as net loss attributable to Holdings. See Notes 1, 3 and 5.

SOUTHCROSS ENERGY LLC PREFERRED

SOUTHCROSS ENERGY LLC PREFERRED UNITS	12 Months Ended
	Dec. 31, 2014
Temporary Equity Disclosure [Abstract]
SOUTHCROSS ENERGY LLC PREFERRED UNITS	SOUTHCROSS ENERGY LLC PREFERRED UNITS In connection with our IPO and through a series of transactions described in Note 12, Southcross Energy LLC contributed all of its operating subsidiaries (its net assets on a historical cost basis), excluding certain liabilities, common units and all preferred units, and became the holding company of us. This note discloses Southcross Energy LLC's preferred units as of November 7, 2012 (our IPO date), as well as the activity associated with the preferred units for the period from January 1, 2012 through our IPO. None of the preferred units (Preferred, Redeemable Preferred and Series B Redeemable Preferred) were conveyed in our IPO, and remained the obligation of Southcross Energy LLC and not us. All of the Redeemable Preferred Units and Series B Redeemable Preferred Units have since been redeemed. Preferred Units As of November 7, 2012, Southcross Energy LLC's cumulative preferred units were comprised of 11,850,374 units with a par value of $10 per unit, which accrued value (in the form of additional preferential rights to receive distributions) at a rate of 10% per annum, compounded quarterly. Except in the case of cash distributions made for the purpose of paying federal income taxes, which are made to both preferred and common equity owners in direct proportion to the owners' respective share of taxable income, owners of the preferred equity receive cash distributions before owners of common equity. The cumulative preferred units and their cumulative return are subordinated to all redeemable preferred units and their cumulative return as discussed below. With the exception of cash distributions for federal income tax purposes, the Credit Agreement included certain covenants that restricted Southcross Energy LLC's ability to pay cash dividends to its owners. Southcross Energy LLC adjusts the carrying value of the Preferred Units to reflect the cumulative right to receive distributions on a quarterly basis. As of November 7, 2012, and December 31, 2011, the preferred units' cumulative right to receive future cash distributions was $43.3 million and $31.8 million , respectively, as a result of the cumulative preferred return on such units. Redeemable Preferred Units As mentioned above, none of the redeemable preferred units were conveyed in our IPO, and they remained the obligation of Southcross Energy LLC. On June 10, 2011, in connection with Southcross Energy LLC entering into the Credit Agreement, Charlesbank and certain of Southcross Energy LLC's existing investors contributed a total of $15.0 million in exchange for 1.5 million Redeemable Preferred Units. The Redeemable Preferred Units had a par value of $10 per unit and accrued value (in the form of an additional preferential right to receive distributions) at a rate of 18% per annum, compounded quarterly. These Redeemable Preferred Units could be redeemed in whole or in part at any time, or would be redeemed by Southcross Energy LLC promptly after the satisfaction of all obligations under the Credit Agreement, to the extent of available funds. Southcross Energy LLC adjusted the carrying value of the Redeemable Preferred Units to reflect the cumulative right to receive distributions on a quarterly basis. As of November 7, 2012, the right of the Redeemable Preferred Units to receive future cash distributions included an additional $3.9 million as a result of the cumulative preferred return on such units. All of the Redeemable Preferred Units have since been redeemed. Series B Redeemable Preferred Units As mentioned above, none of the redeemable preferred units were conveyed in our IPO, and they remained the obligation of Southcross Energy LLC. On March 20, 2012, Charlesbank and certain of Southcross Energy LLC's existing investors contributed $25.3 million and an affiliate of Wells Fargo Securities, LLC contributed $10.0 million to Southcross Energy LLC in exchange for 2.53 million units and 1.0 million units, respectively, of a new, Series B class, of Redeemable Preferred Units ("Series B Units"). On June 26, 2012, Charlesbank and certain of Southcross Energy LLC's existing investors contributed $7.5 million to Southcross Energy LLC in exchange for 0.75 million Series B Units. On November 7, 2012 and subsequent to our IPO, the Series B Units were comprised of 3.35 million units. On November 26, 2012 and subsequent to the Over-Allotment Option, Southcross Energy LLC redeemed 2.49 million units. The Series B Units have a par value of $10 per unit, which accrued value (in the form of an additional preferential right to receive distributions) at a rate of 18% per annum, compounded quarterly. The Series B Units could be redeemed by Southcross Energy LLC in whole or in part at any time, or would be redeemed by Southcross Energy LLC promptly after the satisfaction of all its obligations under the Credit Agreement, to the extent of available funds. Southcross Energy LLC adjusts the carrying value of the Series B Units to reflect the cumulative right to receive distributions on a quarterly basis. As of November 7, 2012 and November 26, 2012, the Series B Units' right to receive future cash distributions included $3.8 million and $4.4 million , respectively as a result of the cumulative preferred return. All of the Series B Units have since been redeemed. Series C Redeemable Preferred Units As mentioned above, none of the redeemable preferred units were conveyed in our IPO, and they remained the obligation of Southcross Energy LLC. On June 26, 2012, Charlesbank and certain of Southcross Energy LLC's existing investors and other institutional investors contributed $30.0 million to Southcross Energy LLC in exchange for 3.0 million units of a new, Series C class, of Redeemable Preferred Units ("Series C Units"). As of November 7, 2012, the Series C Units were comprised of 3.0 million units with a par value of $10 per unit, which accrue value (in the form of an additional preferential right to receive distributions) at a rate of 18% per annum, compounded quarterly. The Series C Units and their cumulative preferred return of $1.4 million as of November 7, 2012 were fully redeemed in connection with our IPO (See Note 12).

INCENTIVE COMPENSATION

INCENTIVE COMPENSATION	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
UNIT BASED COMPENSATION	INCENTIVE COMPENSATION Unit Based Compensation Long-Term Incentive Plan On November 7, 2012, and in connection with our initial public offering, we established the 2012 Long-Term Incentive Plan (“LTIP”), which provides incentive awards to eligible officers, employees and directors of our General Partner. Awards granted to employees under the LTIP vest over a three -year period in equal annual installments or in the event of a change in control of our General Partner in either a common unit or an amount of cash equal to the fair market value of a common unit at the time of vesting, as determined by management at its discretion. These awards also include distribution equivalent rights that grant the holder the right to receive an amount equal to the cash distributions on common units during the period the award remains outstanding. The following table summarizes information regarding awards of units granted under the LTIP: Units Weighted-Average Fair Unvested - December 31, 2014 470,750 $ 20.45 Granted units 372,283 $ 13.80 Forfeited units (17,514 ) $ 20.69 Unvested - March 31, 2015 825,519 $ 18.15 For the three months ended March 31, 2015 and 2014, we granted awards under the LTIP with a grant date fair value of $5.1 million and $36 thousand , respectively, which we have classified as equity awards. As of March 31, 2015 and March 31, 2014, we had total unamortized compensation expense of $12.9 million and $3.2 million , respectively, related to unvested awards. Compensation expense associated with awards granted in the three months ended March 31, 2015 of 84,423 are expected to be recognized over a one-year vesting period, while the remaining awards are expected to be recognized over the three-year vesting period from each equity award’s grant date. As of March 31, 2015 and March 31, 2014, we had 545,515 and 1,525,121 units, respectively, available for issuance under the LTIP. A grant of 84,423 units was made to the officers of our General Partner on March 10, 2015 that have a one-year vesting period rather than a three -year vesting period. These executive awards granted in March 2015 were not compensation earned for performance in 2014. Unit Based Compensation Expense The following table summarizes information regarding recognized compensation expense, which is included in general and administrative and operations and maintenance expense on our statements of operations (in thousands): Three Months Ended March 31, 2015 2014 Unit-based compensation $ 813 $ 529 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 $17,500 annually for the period. The following table summarizes information regarding contributions and the expense recognized for the matching contributions, which is included in general and administrative expense on our statements of operations (in thousands): Three Months Ended March 31, 2015 2014 Matching contributions expensed for employee savings plan $ 181 $ 356 2014 Incentive Plan On August 4, 2014, our General Partner and Southcross GP Management Holdings, LLC, a Delaware limited liability company of which Holdings is the sole managing member (“GP Management”), adopted the Southcross Energy Partners GP, LLC and Southcross GP Management Holdings, LLC 2014 Equity Incentive Plan (the “2014 Incentive Plan”). Under the 2014 Incentive Plan, employees, consultants and directors of our General Partner and GP Management will be eligible to receive incentive compensation awards. The 2014 Incentive Plan generally provides for the grant of awards, from time to time at the discretion of the board of directors of our General Partner (and, as applicable, the board of directors of the general partner of Holdings), of non-voting units in our General Partner to GP Management and then a corresponding grant or award of non-voting units of GP Management to the employee, consultant or director. In connection with the adoption of the 2014 Incentive Plan, our General Partner amended and restated its limited liability company agreement and entered into its Second Amended and Restated Limited Liability Company Agreement which establishes a new class of non-voting units for issuance pursuant to the 2014 Incentive Plan and designates Southcross Holdings Borrower LP, a wholly owned subsidiary of Holdings as our General Partner’s managing member. As of March 31, 2015, no awards had been granted under this plan.	INCENTIVE COMPENSATION Unit Based Compensation Long-Term Incentive Plan On November 7, 2012, and in connection with our IPO, we established the LTIP, which provides incentive awards to eligible officers, employees and directors of our General Partner. Awards granted to employees under the LTIP vest over a three year period in equal annual installments or in the event of a change in control of our General Partner in either a common unit or an amount of cash equal to the fair market value of a common unit at the time of vesting, as determined by management at its discretion. These awards also include distribution equivalent rights that grant the holder the right to receive an amount equal to the cash distributions on common units during the period the award remains outstanding. The following table summarizes information regarding awards of units granted under the LTIP: Units Weighted-Average Fair Value at Grant Date Unvested - November 7, 2012 — $ — Granted units 146,000 23.01 Forfeited units (1,500 ) 23.01 Vested units — — Unvested - December 31, 2012 144,500 $ 23.01 Granted units 112,179 21.96 Forfeited units (20,700 ) 22.09 Units recaptured for tax withholdings (13,034 ) 23.01 Vested units (40,272 ) 22.30 Unvested - December 31, 2013 182,673 $ 22.55 Granted units 787,321 19.82 Forfeited units (1,050 ) 23.01 Units recaptured for tax withholdings (159,500 ) 17.06 Vested units (338,694 ) 17.45 Unvested - December 31, 2014 470,750 $ 20.45 For the years ended December 31, 2014 and 2013, we granted awards under the LTIP, with a grant date fair value of $15.6 million and $2.5 million , respectively, which we have classified as equity awards. As of December 31, 2014 and 2013, we had total unamortized compensation expense of $9.1 million and $3.6 million , respectively, related to these units. The awards were expected to be amortized over the three -year vesting period from each equity award's grant date. The Holdings Transaction on August 4, 2014 resulted in a change of control of our General Partner and accelerated the vesting of all the LTIP awards and distribution equivalent rights outstanding on that date. As of December 31, 2014 and 2013, we had 900,284 and 1,527,055 units, respectively, 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): Year Ended December 31, 2014 2013 2012 Unit-based compensation $ 10,074 (1) $ 2,186 $ 630 ____________________________________________________________________________ (1) This amount includes $7.2 million related to the accelerated vesting of the LTIP awards and $0.1 million related to the vesting of the Southcross Energy LLC equity equivalent units as a result of the change in control that took place on August 4, 2014. Southcross Energy LLC Phantom Units Southcross Energy LLC provided certain key non-officer employees with equity incentive units ("Phantom Units") in Southcross Energy LLC. The Phantom Units vest upon the occurrence of a change in control where more than 50% of the voting power of Southcross Energy LLC changes hands, or upon the occurrence of a liquidity event where, through the sale of some portion of its ownership, the majority owner of Southcross Energy LLC achieves or exceeds a targeted rate of return on its original investment. The changes in structure and ownership as a result of our IPO did not create a change of control event under the vesting terms of the Phantom Units. The number of Phantom Units earned and eligible for vesting increases over a period of years or through the achievement of certain rates of return by the majority owner of the Southcross Energy LLC or a combination thereof. As of December 31, 2014 and 2013, no fair value was attributable to the Phantom Units. No compensation expense associated with these units was recorded during the year ended December 31, 2014 and 2013. As of December 31, 2013, the number of authorized and issued Phantom Units was 10,832 . Southcross Energy LLC Equity Equivalent Units On April 1, 2012, Southcross Energy LLC granted 15,000 equity equivalent units ("EEUs") to a member of management. Each individual EEU is equivalent in economic value to one Class A Common Unit of Southcross Energy LLC on a fully diluted basis. The EEUs had time and performance vesting over a three year term. In conjunction with the closing of the Holdings Transaction, the 15,000 outstanding EEUs subject to change of control provisions vested on August 4, 2014. The Partnership recognized $0.1 million in general and administrative expenses in the statements of operations for the year ended December 31, 2014 in connection with the accelerated vesting of the EEUs. Compensation expense for the EEUs recognized in general and administrative expenses on the statements of operation was $0.6 million and $0.4 million for the year ended December 31, 2013 and 2012, respectively. Employee Savings Plan We have employee savings plans under Sections 401(a) and 401(k) of the Internal Revenue Code, 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 the employee's contribution up to the lesser of 6% of the employee's eligible compensation or $17,500 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): Year Ended December 31, 2014 2013 2012 Matching contributions expensed for employee savings plan $ 927 $ 628 $ 512 2014 Incentive Plan On August 4, 2014, our General Partner and Southcross GP Management Holdings, LLC, a newly formed entity of which Holdings is the sole managing member (“GP Management”), adopted the Southcross Energy Partners GP, LLC and Southcross GP Management Holdings, LLC 2014 Equity Incentive Plan (the “2014 Incentive Plan”). Under the 2014 Incentive Plan, employees, consultants and directors of our General Partner and GP Management will be eligible to receive incentive compensation awards. The 2014 Incentive Plan generally provides for the grant of awards, from time to time at the discretion of the board of directors of our General Partner (and, as applicable, the board of directors of the general partner of Holdings), of non-voting units in our General Partner to GP Management and then a corresponding grant or award of non-voting units of GP Management to the employee, consultant or director. In connection with the adoption of the 2014 Incentive Plan, our General Partner amended and restated its limited liability company agreement and entered into its Second Amended and Restated Limited Liability Company Agreement which establishes a new class of non-voting units for issuance pursuant to the 2014 Incentive Plan and designates Holdings as our General Partner’s managing member. As of December 31, 2014, no awards had been granted under this plan.

REVENUES

REVENUES	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Revenues [Abstract]
REVENUES	REVENUES We had revenues consisting of the following categories (in thousands): Three Months Ended March 31, 2015 2014 Sales of natural gas $ 112,786 $ 145,358 Sales of NGLs and condensate 37,183 51,874 Transportation, gathering and processing fees 35,053 16,115 Other 916 244 Total revenues $ 185,938 $ 213,591	REVENUES We had revenues consisting of the following categories (in thousands): Year ended December 31, 2014 2013 2012 Sales of natural gas $ 530,947 $ 405,206 $ 325,421 Sales of NGLs and condensate 226,218 169,523 124,139 Transportation, gathering and processing fees 90,807 59,392 46,113 Other 541 601 456 Total revenues $ 848,513 $ 634,722 $ 496,129

EQUITY IN JOINT VENTURES (Notes

EQUITY IN JOINT VENTURES (Notes)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments and Joint Ventures Disclosure [Text Block]	INVESTMENTS IN JOINT VENTURES Assets acquired through the TexStar Rich Gas System Transaction include equity interests in three joint ventures. During 2012, a subsidiary of TexStar and a company subsequently acquired by Atlas Pipeline Partners, L.P. (“Atlas”) formed T2 Eagle Ford Gathering Company LLC (“T2 Eagle Ford”), T2 LaSalle Gathering Company LLC (“T2 LaSalle”) and T2 EF Cogeneration Holdings LLC (“T2 Cogen”, and collectively “T2 Rich Gas System”) to construct and operate a pipeline and cogeneration facility located in South Texas. During 2015, Atlas was acquired by Targa Pipeline Partners LP, which is now our joint venture partner. The Partnership indirectly has a 50% interest in T2 Eagle Ford, a 50% interest in T2 Cogen and a 25% interest in T2 LaSalle. The joint ventures’ summarized financial data from their statements of operations for the three months ended March 31, 2015 is as follows (in thousands): Three Months Ended March 31, 2015 T2 Eagle Ford T2 Cogen T2 LaSalle Revenue $ 921 $ 1,662 $ 379 Net loss (4,997 ) (1,361 ) (1,520 ) The Partnership’s equity in losses of joint venture investments is comprised of the following for the three months ended March 31, 2015 (in thousands): Three Months Ended March 31, 2015 T2 Eagle Ford $ (2,491 ) T2 Cogen (681 ) T2 LaSalle (380 ) Equity in losses of joint venture investments $ (3,552 ) The Partnership’s investments in joint ventures is comprised of the following as of March 31, 2015 (in thousands): March 31, 2015 T2 Eagle Ford $ 107,237 T2 Cogen 19,444 T2 LaSalle 18,994 Investments in joint ventures $ 145,675	INVESTMENTS IN JOINT VENTURES Assets acquired through the TexStar Rich Gas System Transaction include equity interests in three joint ventures. During 2012, a subsidiary of TexStar and a company subsequently acquired by Atlas Pipeline Partners, L.P. formed T2 Eagle Ford Gathering Company LLC (“T2 Eagle Ford”), T2 LaSalle Gathering Company LLC (“T2 LaSalle”) and T2 EF Cogeneration Holdings LLC (“T2 Cogen”) to construct and operate a pipeline and cogeneration facility located in South Texas. The Partnership indirectly has a 50% interest in T2 Eagle Ford, a 50% interest in T2 Cogen and a 25% interest in T2 LaSalle. The joint ventures’ summarized financial data from their statements of operations since we obtained our equity interests in the joint ventures on August 4, 2014 is as follows (in thousands): Year Ended December 31, 2014 T2 Eagle Ford T2 Cogen T2 LaSalle Revenue $ 3,537 $ 2,517 $ 1,163 Net loss (6,277 ) (4,281 ) (1,876 ) The Partnership’s equity in losses of joint venture investments is comprised of the following for the year ended December 31, 2014 (in thousands): Year Ended December 31, 2014 T2 Eagle Ford $ (3,656 ) T2 Cogen (2,141 ) T2 LaSalle (699 ) Equity in losses of joint venture investments $ (6,496 ) The Partnership’s investments in joint ventures is comprised of the following as of December 31, 2014 (in thousands): December 31, 2014 T2 Eagle Ford $ 108,185 T2 Cogen 19,615 T2 LaSalle 19,298 Investments in joint ventures $ 147,098 The joint ventures’ summarized financial data from their balance sheets as of December 31, 2014 is as follows (in thousands): Year Ended December 31, 2014 T2 Cogen T2 Eagle Ford T2 LaSalle Current assets $ 8,923 $ 4,173 $ 904 Property, plant and equipment, net 38,851 216,863 77,189 Total assets 47,774 221,036 78,093 Total liabilities 8,547 3,915 904 Total equity 39,227 217,121 77,189 Total liabilities and equity $ 47,774 $ 221,036 $ 78,093 The joint ventures’ summarized financial data from their statements of operations since we obtained our equity interests in the joint ventures on August 4, 2014 is as follows (in thousands): Year Ended December 31, 2014 T2 Eagle Ford T2 Cogen T2 LaSalle Revenue $ 3,537 $ 2,517 $ 1,163 Net loss (6,277 ) (4,281 ) (1,876 ) The Partnership’s equity in losses of joint venture investments is comprised of the following for the year ended December 31, 2014 (in thousands): Year Ended December 31, 2014 T2 Eagle Ford $ (3,656 ) T2 Cogen (2,141 ) T2 LaSalle (699 ) Equity in losses of joint venture investments $ (6,496 ) The Partnership’s investments in joint ventures is comprised of the following as of December 31, 2014 (in thousands): December 31, 2014 T2 Eagle Ford $ 108,185 T2 Cogen 19,615 T2 LaSalle 19,298 Investments in joint ventures $ 147,098 The joint ventures’ summarized financial data from their balance sheets as of December 31, 2014 is as follows (in thousands): Year Ended December 31, 2014 T2 Cogen T2 Eagle Ford T2 LaSalle Current assets $ 8,923 $ 4,173 $ 904 Property, plant and equipment, net 38,851 216,863 77,189 Total assets 47,774 221,036 78,093 Total liabilities 8,547 3,915 904 Total equity 39,227 217,121 77,189 Total liabilities and equity $ 47,774 $ 221,036 $ 78,093

CONCENTRATION OF CREDIT RISK AN

CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Risks and Uncertainties [Abstract]
CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE	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 months ended March 31, 2015 and 2014 represent the following percentages of consolidated revenue: Three Months Ended March 31, 2015 2014 Top ten customers 60.1 % 64.6 % The percentage of total consolidated revenue for each customer that exceeded 10% of total revenues for the three months ended March 31, 2015 and 2014 was as follows: Three Months Ended March 31, 2015 2014 Trafigura Trading LLC 10.9 % 12.2 % For the three months ended March 31, 2015 and 2014, we did not experience significant non-payment for services. At March 31, 2015 and December 31, 2014, we did not record an allowance for uncollectible accounts receivable.	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 years ended December 31, 2014, 2013 and 2012 represent the following percentages of consolidated revenue: Year Ended December 31, 2014 2013 2012 Top ten customers 63.4 % 59.7 % 65.5 % The percentage of total consolidated revenue for each customer that exceeded 10% of total revenues for the years ended December 31, 2014, 2013 and 2012 was as follows: Year Ended December 31, 2014 2013 2012 Trafigura AG 13.6 % 11.7 % 11.0 % Formosa Hydrocarbons Co., Inc. (a),(b) (a),(b) 24.3 % ____________________________________________________________________________ (a) Information is not provided for periods for which the customer or producer was less than 10% of our consolidated revenue. (b) Our contract with Formosa terminated on June 1, 2013. During the years ended December 31, 2014, 2013 and 2012, we did not experience significant non-payment for services. At December 31, 2014, 2013 and 2012, we did not record an allowance for uncollectible accounts receivable.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS Partnership Distributions On April 28, 2015, the board of directors of our General Partner declared a cash distribution of $0.40 per common unit and General Partner unit, which will be paid on May 14, 2015 to unitholders of record on May 8, 2015. In addition, on April 28, 2015, the board of directors of our General Partner declared a $0.3257 per unit distribution for the first quarter of 2015 on the Partnership’s Class B Convertible Units. The distribution on the Class B Convertible Units will be paid in the form of additional Class B Convertible Units on May 14, 2015. In order to support the Partnership's acquisition of the TexStar Rich Gas System in August 2014, Holdings has elected to forgo distributions on any subordinated units that would cause the Partnership's distributions to exceed its distributable cash flow for any quarterly period. This election will continue until the Partnership has distributable cash flow in excess of total distributions on the Partnership's common and subordinated units and complies with the new restrictions in the Credit Agreement Amendment (defined below). Amendment to Third A&R Revolving Credit Agreement During the fourth quarter of 2014 and into the first quarter of 2015, as a result of the decline in commodity prices and associated decline in upstream drilling activity, we experienced a decline in the growth in volume of natural gas we gather and process for our customers. Our results in the first quarter of 2015 were also negatively impacted by the fire at our Gregory facility. These collective events impacted our operating results adversely and resulted in the need to amend our Credit Facility. On May 7, 2015, we entered into a First Amendment to our Third A&R Revolving Credit Agreement among the Partnership, as the borrower, Wells Fargo, N.A., as the administrative agent, the lenders and other parties thereto (the “Credit Agreement Amendment”). The Credit Agreement Amendment amended the Third A&R Revolving Credit Agreement. The Credit Agreement Amendment, among other things, (a) revised the maximum consolidated total leverage ratio set at 5.75 to 1.0 as of the last day of the fiscal quarter ending each of March 31, 2015, June 30, 2015 and September 30, 2015, (ii) 5.5 to 1.0 as of the last day of the fiscal quarter ending each of December 31, 2015, March 31, 2016 and June 30, 2016, (iii) 5.25 to 1.0 as of the last day of the fiscal quarter ending September 30, 2016, and (iv) 5.00 to 1.0 as of the last day of each fiscal quarter thereafter, in each case, without any step-ups in connection with acquisitions; (b) increased the applicable margins used in connection with the loans and the commitment fee so that the applicable margin for Eurodollar Loans ranges from 2.00% to 4.50% , the applicable margin for Base Rate Loans ranges from 1.00% to 3.50% and the applicable rate for commitment fees ranges from 0.375% to 0.500% , (c) permits the Partnership to comply with certain Financial Covenants by making certain pro forma adjustments with respect to minimum revenues to be received from Frio, (d) modified our ability to cure Financial Covenant defaults; (e) imposed additional restrictions on our ability to declare and pay quarterly cash distributions with respect to our subordinated units; and (f) amended certain other provisions of the Third A&R Revolving Credit Agreement as more specifically set forth in the Credit Agreement Amendment.	SUBSEQUENT EVENTS Partnership Distribution On January 22, 2015, the board of directors of our General Partner declared a cash distribution of $0.40 per common unit and General Partner unit, which was paid on February 13, 2015 to unitholders of record on February 9, 2015. In addition, on January 22, 2015, the board of directors of our General Partner declared a $0.3257 per unit distribution for the fourth quarter of 2014 on the Partnership’s Class B Convertible Units. The distribution on the Class B Convertible Units was paid in the form of additional Class B Convertible Units on February 13, 2015. In order to support the Partnership's recent acquisition of the TexStar Rich Gas System in August 2014, Holdings has elected to forgo distributions on any subordinated units that would cause the Partnership's distributions to exceed its distributable cash flow for any quarterly period. This election will continue until the Partnership has distributable cash flow in excess of total distributions on the Partnership's common and subordinated units. Holdings has also elected to defer any distribution that is expected to be payable on the subordinated units for the fourth quarter of 2014 until the Partnership files its Form 10-K for its fiscal year ended December 31, 2014. We intend to make a cash distribution with respect to the subordinated units for the fourth quarter of 2014 such that the total of the subordinated, common and cash pay general partner unit distributions is equal to the Partnership’s distributable cash flow for such period. On January 20, 2015, we experienced a fire at our Gregory facility, the exact cause of which is being investigated. There were no injuries in connection with the fire and damage was limited to one of our two processing units at the facility. The Gregory facility includes 135 MMcf/d of gas processing capacity from two processing units with 80 MMcf/d and 55 MMcf/d of capacity, respectively, and an associated 4,800 barrel per day fractionation plant. Damage appears to be limited to the 80 MMcf/d processing unit. The Gregory facility was shut down as a result of the fire for four weeks, and after completing safety reviews, the 55 MMcf/d processing unit was restarted. We do not anticipate a material financial impact as a result of the fire and outage. We maintain insurance that carries a $500,000 deductible and is expected to cover any repair costs in excess of the deductible. The Compensation Committee of the Board of Directors authorized future grants, to be made on March 10, 2015, of phantom units to the executive officers of our General Partner, if such persons remain employed as of such date (the “2015 LTIP Awards”). The number of phantom units to be granted as 2015 LTIP Awards, if at all, will be determined by dividing the award value by the closing price of our common units on March 10, 2015. All of the foregoing phantom unit awards will be made under our LTIP, which is described in Note 14; however, certain awards will have a one -year vesting period rather than a three-year vesting period. These awards are not compensation earned for performance in 2014. See Note 14 for additional information regarding the LTIP.

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Supplemental Cash Flow Elements [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	SUPPLEMENTAL INFORMATION Supplemental Cash Flow Information (in thousands) Three Months Ended March 31, 2015 2014 Supplemental Disclosures: Cash paid for interest, net of amounts capitalized $ 6,841 $ 2,776 Cash paid for taxes, net of refunds received — 23 Supplemental disclosures of non-cash investing and financing activities: Accounts payable related to capital expenditures 22,793 1,628 Change in value recognized in other comprehensive loss — 11 Capital lease obligations 207 307 Accrued distribution equivalent rights on LTIP units 342 76 Class B Convertible unit in-kind distributions 3,712 — Capitalization of Interest Cost We capitalize interest on projects during their construction period. Once a project is placed in service, capitalized interest, as a component of the total cost of the construction, is depreciated over the estimated useful life of the asset constructed. We incurred the following interest costs (in thousands): Three Months Ended March 31, 2015 2014 Total interest costs $ 7,800 $ 3,072 Capitalized interest included in property, plant and equipment, net (302 ) (99 ) Interest expense $ 7,498 $ 2,973 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 other assets on the balance sheets. Changes in deferred financing costs are as follows (in thousands): 2015 2014 Deferred financing costs, January 1 $ 16,602 $ 5,237 Capitalization of deferred financing costs (1) 6 156 Amortization of deferred financing costs (737 ) (337 ) Deferred financing costs, March 31 $ 15,871 $ 5,056 (1) See Note 6. Southcross Assets Considered Leases to Third Parties In connection with the Onyx acquisition in March 2014, we acquired natural gas pipelines and contracts related to the acquired pipelines (see Note 2). The pipelines transport natural gas to two power plants in Nueces County, Texas under fixed-fee contracts. The contracts have a primary term through 2029 and an option to extend the agreements by an additional term of up to ten years. These contracts are considered operating leases under the applicable accounting guidance. Future minimum annual demand payment receipts under these agreements as of March 31, 2015 were as follows: $4.2 million for the remainder of 2015; $5.6 million in 2016; $5.6 million in 2017; $2.2 million in 2018; $2.2 million in 2019; and $15.3 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 $0.2 million for the three months ended March 31, 2015 and 2014, respectively, and have been included within transportation, gathering and processing fees within Note 12. 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 12 were $0.8 million and $1.2 million for the three months ended March 31, 2015 and 2014, respectively.	SUPPLEMENTAL CASH FLOW INFORMATION Year Ended December 31, 2014 2013 2012 Supplemental Disclosures: Cash paid for interest $ 16,206 $ 13,043 $ 10,552 Cash received for tax refunds 205 95 315 Supplemental schedule of non-cash investing and financing activities: Accounts payable related to capital expenditures 29,645 4,946 40,707 Change in value recognized in other comprehensive income 11 148 745 Capital lease obligation 708 1,396 — Accrued distribution equivalent rights on the LTIP units 167 279 — Series A Convertible preferred unit in-kind distributions and fair value adjustments 5,129 — — Class B Convertible unit issuance, net 324,413 — — Class B Convertible unit in-kind distributions 9,610 — — Consideration paid in excess of purchase price for the TexStar Rich Gas System 98,625 — — Settlement of EEU liability by Southcross Energy LLC 1,151 — — Non-cash capitalized interest for 2015 Holdings Acquisition 323 — — Consolidation of Valley Wells' net assets 33,165 — —

SUPPLEMENTAL SELECTED QUARTERLY

SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)	12 Months Ended
	Dec. 31, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)	SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) The following presents a summary of selected quarterly financial information (in thousands, except per unit data): Quarters ended 2014 March 31 June 30 September 30 (1) December 31 (1) Revenues $ 213,591 $ 195,063 $ 212,676 $ 227,182 Gross operating margin 27,188 26,237 32,115 41,841 (Loss) income from operations 1,692 (1,134 ) (15,658 ) 1,872 Net loss (1,289 ) (2,961 ) (26,032 ) (2) (7,448 ) Basic and diluted net loss per common unit (0.06 ) (0.34 ) (0.49 ) 0.05 Basic and diluted net loss per subordinated unit (0.06 ) (0.11 ) (0.49 ) 0.05 Quarters ended 2013 March 31 June 30 September 30 December 31 Revenues $ 144,250 $ 154,703 $ 160,629 $ 175,140 Gross operating margin 18,863 21,296 25,213 28,174 (Loss) income from operations (4,317 ) (2,831 ) (357 ) 4,510 Net (loss) income (6,382 ) (6,192 ) (4,069 ) 673 Basic net (loss) income per common unit (0.26 ) (0.65 ) 0.19 (0.01 ) Diluted net loss per common unit (0.26 ) (0.65 ) (0.14 ) (0.01 ) Basic and diluted net loss per subordinated unit (0.26 ) (0.27 ) (0.19 ) (0.01 ) ____________________________________________________________________________ (1) Due to the common control aspects in the 2015 Holdings Acquisition, 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 the Compression Assets for all periods ending after August 4, 2014, the date of the Holdings Transaction. (2) See Note 4.

BASIS OF PRESENTATION (Policies

BASIS OF PRESENTATION (Policies)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation We prepared this report under the rules and regulations of the Securities and Exchange Commission 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 the recasted financial statements and financial information filed on a Current Report on Form 8-K on August 20, 2015 (collectively referred herein as the "Recast 2014 Annual Report on Form 10-K"). The condensed consolidated financial statements as of March 31, 2015 and December 31, 2014, and for the three months ended March 31, 2015 and 2014, are unaudited and have been prepared on the same basis as the audited financial statements included in our Recast 2014 Annual Report on Form 10-K. Adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the results of operations and financial position have been included herein. All intercompany accounts and transactions have been eliminated in the preparation of the accompanying condensed consolidated financial statements. The condensed consolidated financial statements reflect the assets acquired and liabilities assumed and the related operating results associated with (i) the Onyx pipelines acquisition beginning on March 6, 2014, (ii) the TexStar Rich Gas System Transaction and the 2015 Holdings Acquisition beginning on August 4, 2014, (iii) and the Texoz acquisition beginning on November 21, 2014. See Note 2. As a result of the Holdings Transaction, Holdings acquired a controlling equity interest in the Partnership, which was accounted for under the acquisition method of accounting in the consolidated financial statements of Holdings, whereby Holdings recorded the Partnership’s assets acquired and liabilities assumed at fair value. However, because less than 80% of the equity interests in the Partnership were acquired, push down accounting of Holdings’ basis in the Partnership was prohibited in our consolidated financial statements. Additionally, because the TexStar Rich Gas System was owned by TexStar, the Partnership recorded the TexStar Rich Gas System at TexStar’s historical cost. Thus, the difference between consideration paid and the TexStar Rich Gas System’s historical cost (net book value) at August 4, 2014, the date on which the Holdings Transaction and the TexStar Rich Gas System Transaction closed, was recorded as a reduction to partners’ capital. Management concluded that the Partnership was the predecessor for accounting purposes for periods prior to August 4, 2014. We recognized the 2015 Holdings Acquisition 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) on May 7, 2015, the date on which the 2015 Holdings Acquisition closed, was recorded as a reduction 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 Recast 2014 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 repor	Basis of Presentation The accompanying consolidated financial statements and related notes present the consolidated balance sheets as of December 31, 2014 and 2013 and the consolidated statements of operations, comprehensive income (loss), cash flows and changes in partners' capital and members' equity for the years ended December 31, 2014, 2013 and 2012 (See Note 2). As a result of our IPO, there was no change in the accounting basis of the contributed net assets of Southcross Energy LLC. Information included in these financial statements and related notes are presented as if we and Southcross Energy LLC were the same entity, except with respect to associated changes in capitalization as described in Note 12. The consolidated financial statements reflect the assets acquired and liabilities assumed and the related operating results beginning on March 6, 2014 associated with the Onyx pipelines acquisition as discussed further in Note 3. The consolidated financial statements also reflect the TexStar Rich Gas System Transaction and the 2015 Holdings Acquisition and the related operating results beginning on August 4, 2014, as discussed further in Note 3. As a result of the Holdings Transaction, Holdings acquired a controlling equity interest in the Partnership, which was accounted for under the acquisition method of accounting in the consolidated financial statements of Holdings, whereby Holdings recorded the Partnership’s assets acquired and liabilities assumed at fair value. However, because less than 80% of the equity interests in the Partnership were acquired, push down accounting of Holdings’ basis in the Partnership was prohibited in our consolidated financial statements. Additionally, because the TexStar Rich Gas System was owned by TexStar, the Partnership recorded the TexStar Rich Gas System at TexStar’s historical cost. Thus, the difference between consideration paid and the TexStar Rich Gas System’s historical cost (net book value) at August 4, 2014, the date on which the Holdings Transaction and the TexStar Rich Gas System Transaction closed, was recorded as a reduction to partners’ capital. Management concluded that the Partnership was the predecessor for accounting purposes for periods prior to August 4, 2014. We recognized the 2015 Holdings Acquisition 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 3. The accompanying consolidated financial statements were prepared in accordance with accounting principles generally accepted in the U.S. ("GAAP") and in accordance with the rules and regulations of the U.S. Securities and Exchange Commission ("SEC"). Our consolidated financial statements include the accounts of Southcross and its 100% owned subsidiaries. We eliminate all intercompany balances and transactions in preparing consolidated financial statements.
Principles of Consolidation		Principles of Consolidation We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. We do not have ownership in any consolidated variable interest entities.
Use of Estimates		Use of Estimates The preparation of the consolidated financial statements in conformity with GAAP 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 consolidated financial statements and the reported amounts of revenues and expenses during the period. Actual results may differ from those estimates.
Cash and Cash Equivalents		Cash and Cash Equivalents We consider all short-term investments with an original maturity of three months or less to be cash equivalents. At December 31, 2014 and 2013, except for amounts held in bank accounts to cover current payables, all of our cash equivalents were invested in short-term money market accounts and overnight sweep accounts.
Allowance for Doubtful Accounts		Allowance for Doubtful Accounts In evaluating the collectability of our accounts receivable, we perform credit evaluations of our new customers and adjust payment terms based upon payment history and each customer's current creditworthiness, as determined by our review of such customer's credit information. We extend credit on an unsecured basis to many of our customers. At December 31, 2014 and 2013, we have recorded no allowance for uncollectible accounts receivable.
Debt Issuance Costs		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 other assets on the consolidated balance sheets.
Long-Lived Assets		Impairment of Long-Lived Assets We evaluate our long-lived assets, which include finite-lived intangible assets, for impairment when events or circumstances indicate that their carrying values may not be recoverable. These events include, but are not limited to, market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, we evaluate the recoverability of our carrying value based on the long-lived asset's ability to generate future cash flows on an undiscounted basis. If the undiscounted cash flows are not sufficient to recover the long-lived asset's carrying value, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying values of the asset downward, if necessary, to their estimated fair value. Our fair value estimates are generally based on assumptions market participants would use, including market data obtained through the sales process or an analysis of expected discounted cash flows. With the recent decline in commodity prices negatively affecting the level of natural gas and crude oil production, we are more susceptible to potential impairment. During the year ended December 31, 2014, we recorded $1.6 million of impairment costs primarily related to right of way costs on a canceled project. We did not record any impairments during the years ended 2013 and 2012.
Capitalization of Interest Cost		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.
Asset Retirement Obligations		Asset Retirement Obligations We evaluate whether any future asset retirement obligations ("AROs") exist and estimate the costs for such AROs for certain future events. An ARO will be recorded in the periods where we can reasonably determine the settlement dates or the period in which the expense is incurred and an estimated cost of the retirement obligation. Generally we do not have the intention of discontinuing the use of any significant assets or have a legal obligation to do so. Therefore, in these situations we do not have sufficient information to reasonably estimate any future AROs. However, during the year ended December 31, 2013, an asset retirement obligation of $0.5 million related to the discontinued use of an asset was recorded in operations and maintenance expense. This ARO is substantially complete and we do not expect significant additional costs. No AROs were recorded for the years ended December 31, 2014.
Environmental Costs and Other Contingencies		Environmental Costs and Other Contingencies We recognize liabilities for environmental and other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and no specific amount in that range is more likely than any other, the low end of the range is accrued.
Revenue Recognition		Revenue Recognition Using the revenue recognition criteria of persuasive evidence of an exchange arrangement exists, delivery has occurred or services have been rendered and the price is fixed or determinable, we record natural gas and NGL revenue in the period when the physical product is delivered to the customer and in an amount based on the pricing terms of an executed contract. Our transportation, compression, processing, fractionation and other revenue is recognized in the period when the service is provided and includes our fee-based service revenue. In addition, collectability is evaluated on a customer-by-customer basis. New customers are subject to a credit review process, which evaluates the customers' financial position and their ability to pay. Our sale and purchase arrangements are primarily accounted for on a gross basis in the statements of operations. These transactions are contractual arrangements that establish the terms of the purchase of natural gas or NGLs at a specified location and the sale of natural gas or NGLs at a different location on the same or on another specified date. These transactions require physical delivery and transfer of the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk. We derive revenue in our business from the following types of arrangements: • Fixed-Fee. We receive a fixed-fee per unit of natural gas volume that we gather at the wellhead, process, treat, compress and/or transport for our customers, or we receive a fixed-fee per unit of NGL volume that we fractionate. Some of our arrangements also provide for a fixed-fee for guaranteed transportation capacity on our systems. • Fixed-Spread. Under these arrangements, we purchase natural gas and NGLs from producers or suppliers at receipt points on our systems at an index price plus or minus a fixed price differential and sell these volumes of natural gas and NGLs at delivery points off our systems at the same index price, plus or minus a fixed price differential. By entering into such back-to-back purchases and sales, we are able to mitigate our risk associated with changes in the general commodity price levels of natural gas and NGLs. We remain subject to variations in our fixed-spreads to the extent we are unable to precisely match volumes purchased and sold in a given time period or are unable to secure the supply or to produce or market the necessary volume of products at our anticipated differentials to the index price. • Commodity-Sensitive. In exchange for our processing services, we may remit to a customer a percentage of the proceeds from our sales, or a percentage of the physical volume, of residue natural gas and/or NGLs that result from our natural gas processing, or we may purchase NGLs from customers at set fixed NGL recoveries and retain the balance of the 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.
Fair Value of Financial Instruments		Fair Value of Financial Instruments Accounting guidance requires the disclosure of the fair value of all financial instruments that are not otherwise recorded at fair value in the financial statements. At December 31, 2014 and 2013, financial instruments recorded at contractual amounts that approximate fair value include certain funds on deposit, accounts receivable, other receivables and accounts payable and accrued liabilities. The fair values of such items are not materially sensitive to shifts in market interest rates because of the short term to maturity of these instruments (See Note 6).
Derivative Instruments		Derivative Instruments In our normal course of business, we enter into month-ahead commodity swap contracts in order to hedge economically our exposure to certain intra-month natural gas index pricing risk. We manage our interest rate risk through interest rate swaps and interest rate caps (See Note 6). Derivative financial instruments are recorded in the consolidated balance sheets at fair value, except for derivative contracts that we qualify for and for which we have elected the normal purchase or normal sale exceptions, which are not reflected in the consolidated balance sheets or statements of operations prior to accrual of the settlement. We present our derivative assets and liabilities on a net basis. If certain criteria are met, a derivative financial instrument may be designated as a fair value hedge or cash flow hedge. The changes in fair value of cash flow hedges are deferred in accumulated other comprehensive loss, net of tax, to the extent the contracts are, or have been, effective as hedges, until the forecasted transactions impact earnings. The ineffective portion of changes in fair value of cash flow hedges is recognized immediately into earnings. On an ongoing basis, a derivative instrument designated as a cash flow hedge must be highly effective in offsetting changes in cash flows of the hedged item. If it is determined that the derivative instrument is not highly effective as a hedge, hedge accounting will be discontinued prospectively. Changes in fair value of the associated hedging instrument are then recognized immediately in earnings for the remainder of the contract term unless a new hedging relationship is designated. The assessment of effectiveness excludes counterparty default risk and our own non-performance risk. The effect of these valuation adjustments was immaterial for the years ended December 31, 2014 and 2013. Derivative financial instruments designated as cash flow hedges must have a high correlation between price movements in the derivative and the hedged item. If and when an acceptable level of correlation no longer exists, hedge accounting ceases and changes in fair value are recognized in our statements of operations. If it becomes probable that a forecasted transaction will not occur, we immediately recognize the related deferred gains or losses in our statements of operations. Changes in fair value of the associated hedging instrument are then recognized immediately in earnings for the remainder of the contract term unless a new hedging relationship is designated. In March 2012, we entered into an interest rate swap to reduce the risks with respect to the variability of the interest rates under our Previous Credit Facility. In February 2014, we discontinued cash flow hedge accounting on a prospective basis as a result of the repayment of borrowings under our Previous Credit Facility (See Note 8). With the exception of these interest rate swaps, we did not have any other derivative financial instruments designated as fair value or cash flow hedges for accounting purposes during the years ended December 31, 2014 and 2013. For our derivative financial instruments that have not been designated as cash flow hedges for accounting purposes, changes in such instruments' fair values are recognized immediately in earnings. We do not hold or issue financial instruments or derivative financial instruments for trading purposes.
Unit-Based Compensation		Unit-Based Compensation Unit-based awards which settle in common units are classified as equity and are recognized in the financial statements over the vesting period at their grant date fair value. Unit-based awards which settle in cash are classified as liabilities and remeasured at every balance sheet date through settlement, such that the vested portion of the liability is adjusted to reflect its revised fair value through compensation expense. Currently, all awards granted under the long-term incentive plan will be settled in common units. Compensation expense associated with unit-based awards, adjusted for forfeitures, is recognized evenly from the date of the grant over the vesting period within general and administrative expenses on our consolidated statements of operations.
Income Taxes		Income Taxes No provision for federal or state income taxes, except as noted below, is included in our statements of operations as such income is taxable directly to our partners. Each partner is responsible for its share of federal and state income tax. Net earnings for financial statement purposes may differ significantly from taxable income reportable to each partner as a result of differences between the tax basis and financial reporting basis of assets and liabilities. We are subject to the Texas margin tax which qualifies as an income tax under GAAP that requires us to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis. Our current tax liability will be assessed based on the gross revenue apportioned to Texas. For the years ended December 31, 2014 and 2013, there were no material temporary differences. On September 13, 2013, the U.S. Department of the Treasury and IRS issued the final and re-proposed tangible property regulations effective for tax years beginning January 1, 2014. The provisions of these regulations had no impact our financial statements.
Uncertain Tax Positions		Uncertain Tax Positions We evaluate the uncertainty in tax positions taken or expected to be taken in the course of preparing our consolidated financial statements to determine whether the tax positions are more likely than not of being sustained by the applicable tax authority. Tax positions deemed not to meet the more likely than not threshold would be recorded as a tax benefit or expense in the current year. We believe that there are no uncertain tax positions and that no provision for income tax is required for these consolidated financial statements.
Earnings per Unit		Earnings per Unit Net income (loss) per unit is calculated under the two-class method of computing earnings per unit when participating or multiple classes of securities exist. Under this method, undistributed earnings or losses for a period are allocated based on the contractual rights of each security to share in those earnings as if all of the earnings for the period had been distributed. Basic net income (loss) per unit excludes dilution and is computed by dividing net income (loss) attributable to limited partner common units by the weighted average number of limited partner common units outstanding during the period. Paid-in kind distributions and valuation adjustments to maximum redemption value of the Series A convertible preferred units (which converted to common units on August 4, 2014) are excluded from income available to common units in the calculation of basic earnings per unit. Dilutive net income (loss) per unit reflects potential dilution from the potential issuance of limited partner common units. Dilutive net income (loss) per unit is calculated using the treasury stock method. It is computed by dividing net income (loss) attributable to limited partner common units by the weighted average number of limited partner common units outstanding during the period increased by the number of additional limited partner common units that would have been outstanding if the dilutive potential limited partner common units had been issued.
New Accounting Pronouncements	Recent Accounting Pronouncements Accounting standard-setting organizations frequently issue new or revised accounting rules. We review new pronouncements to determine their impact, if any, on our consolidated financial statements. We are evaluating the impact of each pronouncement on our consolidated financial statements. In 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. We are currently required to adopt this standard beginning in the first quarter of 2017. On April 1, 2015, the Financial Accounting Standards Board (“FASB”) voted to propose to defer the effective date of the new revenue recognition standard by one year. The FASB plans to disclose its decisions for a 30-day public comment period in a proposed Accounting Standards Update (“ASU”), which is expected to be issued during the second quarter of 2015. In February 2015, the FASB issued an ASU that amended current consolidation guidance with regard to variable interest entities and voting interest entities. All reporting entities will need to re-evaluate and potentially revise their disclosures regarding this topic. This standard will become effective beginning in 2016.	Recent Accounting Pronouncements Accounting standard-setting organizations frequently issue new or revised accounting rules. We review new pronouncements to determine their impact, if any, on our consolidated financial statements. We are evaluating the impact of each pronouncement on our consolidated financial statements. In 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 in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. We are required to adopt this standard beginning in the first quarter of 2017. In 2014, a new discontinued operations standard was issued that will update existing discontinued operations guidance. The standard will raise the threshold for disposals to qualify as discontinued operations. We are required to adopt this standard beginning in the first quarter of 2015. 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. We are required to adopt this standard beginning in the first quarter of 2017.

BASIS OF PRESENTATION BASIS OF

BASIS OF PRESENTATION BASIS OF PRESENTATIONS (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Schedule of Interest Costs Incurred	We incurred the following interest costs (in thousands): Three Months Ended March 31, 2015 2014 Total interest costs $ 7,800 $ 3,072 Capitalized interest included in property, plant and equipment, net (302 ) (99 ) Interest expense $ 7,498 $ 2,973	We incurred the following interest costs (in thousands): Year Ended December 31, 2014 2013 2012 Total interest costs $ 18,649 $ 14,047 $ 12,035 Capitalized interest included in property, plant and equipment, net (3,087 ) (1,457 ) (6,268 ) Interest expense $ 15,562 $ 12,590 $ 5,767
Schedule of Debt Issuance Costs		Changes in deferred financing costs are as follows (in thousands): Year Ended December 31, 2014 2013 Deferred financing costs, January 1 $ 5,237 $ 4,385 Capitalization of deferred financing costs (1) 15,659 2,139 Amortization of deferred financing costs (2) (4,192 ) (1,287 ) Deferred financing costs, December 31 $ 16,602 $ 5,237 ___________________________________________________________________________ (1) See Note 8. (2) This amount includes $2.3 million written off in connection with repayment of the Previous Credit Facility (as defined in Note 8) and contemporaneously entering into the Senior Credit Facilities (as defined in Note 8) in August 2014.

ACQUISITIONS (Tables)

ACQUISITIONS (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Schedule of reconciliation of the fair values of the assets acquired and liabilities assumed related to the EAI purchase price	The amount of the consideration paid over TexStar’s net book value of the assets received and liabilities assumed of the TexStar Rich Gas System was recorded as a reduction to partners’ capital as summarized as follows (in thousands): Consideration paid (1) $ 404,414 Current assets $ 1,295 Property, plant and equipment, net 255,220 Investments in joint ventures (2) 152,050 Total assets contributed 408,565 Total liabilities assumed (3) (102,776 ) Net identifiable assets contributed $ 305,789 Consideration paid in excess of net assets contributed $ 98,625 Allocation of reduction to partners' capital: Common limited partner interest $ 45,420 Class B Convertible limited partner interest 27,925 Subordinated limited partner interest 23,308 General Partner interest 1,972 Total reduction to partners' capital $ 98,625 (1) This amount was calculated as follows: $80 million of cash plus 14,633,000 Class B Convertible Units at an issue price of $22.17 , the closing price of the Partnership’s common units on August 4, 2014. (2) Significant assets acquired through the TexStar Rich Gas System Transaction include equity interests in three joint ventures. See Note 13. (3) This amount includes $100 million of debt assumed. The fair value of the assets acquired and liabilities assumed related to the Onyx purchase price was as follows (in thousands): Purchase Price—Cash $ 38,636 Current assets $ 730 Property, plant and equipment 39,413 Total assets acquired 40,143 Current liabilities assumed (1,407 ) Other liabilities assumed (100 ) Net identifiable assets acquired $ 38,636	The fair value of the assets acquired and liabilities assumed related to the Onyx purchase price was as follows (in thousands): Purchase Price—Cash $ 38,636 Current assets $ 730 Property, plant and equipment 39,413 Total assets acquired 40,143 Current liabilities assumed (1,407 ) Other liabilities assumed (100 ) Net identifiable assets acquired $ 38,636 The amount of the consideration paid over TexStar’s net book value of the assets received and liabilities assumed of the TexStar Rich Gas System is recorded as a reduction to partners’ capital as summarized as follows (in thousands): Consideration paid (1) $ 404,414 Current assets $ 1,295 Property, plant and equipment, net 255,220 Investments in joint ventures (2) 152,050 Total assets contributed 408,565 Total liabilities assumed (3) (102,776 ) Net identifiable assets contributed $ 305,789 Consideration paid in excess of net assets contributed $ 98,625 Allocation of reduction to partners' capital: Common limited partner interest $ 45,420 Class B Convertible limited partner interest 27,925 Subordinated limited partner interest 23,308 General Partner interest 1,972 Total reduction to partners' capital $ 98,625 ____________________________________________________________________________ (1) This amount was calculated as follows: $80 million of cash plus 14,633,000 Class B Convertible Units at an issue price of $22.17 , the closing price of the Partnership’s common units on August 4, 2014. (2) Significant assets acquired through the TexStar Rich Gas System Transaction include equity interests in three joint ventures. See Note 16. (3) This amount includes $100 million of debt assumed.
Schedule of unaudited pro forma financial information Predecessor includes adjustments for income from operations, including depreciation and amortization	Revenues and net income for the previously separate entities and the combined amounts for the three months ended March 31, 2015, are as follows (in thousands): Three Months Ended March 31, 2015 Partnership revenues $ 180,549 Valley Wells System and Compression Assets revenue (1) 5,389 Combined revenues $ 185,938 Partnership net income $ (10,751 ) Valley Wells System and Compression Assets net loss (1) (3,154 ) Combined net income $ (13,905 ) (1) Results are fully reflected in the Partnership's results of operations for the three months ended March 31, 2015. The following unaudited pro forma financial information for the three months ended March 31, 2014 assumes that the acquisition of pipelines from Onyx occurred on January 1, 2013 and includes adjustments for income from operations, including depreciation and amortization, as well as the effects of financing the transaction (in thousands, except unit information): Three Months Ended March 31, 2014 Total revenue $ 214,240 Net loss (1,397 ) Net loss attributable to common unitholders (1,115 ) Net loss per common unit (basic and diluted) (0.06 ) Net loss attributable to subordinated unitholders (745 ) Net loss per subordinated unit (basic and diluted) (0.06 ) The unaudited pro forma information is not necessarily indicative of what our statements of operations would have been	The following unaudited pro forma financial information for the year ended December 31, 2013 and the year ended December 31, 2014 assumes that the acquisition of pipelines from Onyx occurred on January 1, 2013 and includes adjustments for income from operations, including depreciation and amortization, as well as the effects of financing the transaction (in thousands, except unit information): Year Ended December 31, 2014 2013 Total revenue $ 843,376 $ 639,104 Net loss (31,400 ) (18,306 ) Net loss attributable to common unitholders (20,211 ) (9,934 ) Net loss per common unit (basic and diluted) (0.85 ) (0.68 ) Net loss attributable to subordinated unitholders (8,373 ) (9,678 ) Net loss per subordinated unit (basic and diluted) (0.69 ) (0.79 ) Revenues and net income for the previously separate entities and the combined amounts for the year ended December 31, 2014, are as follows (in thousands): Year Ended December 31, 2014 Partnership revenues $ 842,728 Valley Wells System and Compression Assets revenue (1) 5,785 Combined revenues $ 848,513 Partnership net loss $ (31,322 ) Valley Wells System and Compression Assets net loss (1) (6,409 ) Combined net loss $ (37,731 ) _________________________________ (1) Results are fully reflected in the Partnership's results of operations for the year ended December 31, 2014.

EARNINGS PER LIMITED PARTNER 32

EARNINGS PER LIMITED PARTNER UNIT AND DISTRIBUTIONS (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Earnings Per Share [Abstract]
Schedule of reconciliation of net loss attributable to limited partners and limited partner units used in basic and diluted earnings per unit calculations	The following is a reconciliation of the net loss attributable to our limited partners and our limited partner units and the basic and diluted earnings per unit calculations for the three months ended March 31, 2015 and 2014 (in thousands, except unit and per unit data): Three Months Ended March 31, 2015 2014 Net loss $ (13,905 ) $ (1,289 ) Series A Preferred Unit fair value adjustment (1) — 33 Series A Preferred Unit in-kind distribution — (534 ) General partner Unit in-kind distribution (76 ) — Net loss attributable to Holdings (3,154 ) — Net loss attributable to partners $ (10,827 ) $ (1,790 ) General partner's interest (2) (239 ) (26 ) Class B Convertible limited partner interest (2) (3,119 ) — Limited partners' interest (2) Common (4,936 ) (1,045 ) Subordinated (2,533 ) (719 ) (1) The valuation adjustment to maximum redemption value of the Series A Preferred Unit in-kind distribution decreased the net loss attributable to partners for the three months ended March 31, 2014. (2) General Partner's and limited partners’ interests are calculated based on the allocation of net losses for the period, net of the allocation of Series A Preferred Unit in-kind distributions, Series A Preferred Unit fair value adjustments and General Partner unit in-kind distributions. The Class B Convertible Unit interest is calculated based on the allocation of only net losses for the period. Three Months Ended March 31, Common Units 2015 2014 Interest in net loss $ (4,936 ) $ (1,045 ) Effect of dilutive units - numerator (1) — — Dilutive interest in net loss $ (4,936 ) $ (1,045 ) Weighted-average units - basic 23,800,943 18,285,220 Effect of dilutive units - denominator (1) — — Weighted-average units - dilutive 23,800,943 18,285,220 Basic and diluted net loss per common unit $ (0.21 ) $ (0.06 ) Three Months Ended March 31, Subordinated Units 2015 2014 Interest in net loss $ (2,533 ) $ (719 ) Effect of dilutive units - numerator (1) — — Dilutive interest in net loss $ (2,533 ) $ (719 ) Weighted-average units - basic 12,213,713 12,213,713 Effect of dilutive units - denominator (1) — — Weighted-average units - dilutive 12,213,713 12,213,713 Basic and diluted net loss per subordinated unit $ (0.21 ) $ (0.06 ) (1) Because we had a net loss for all periods for common units and the subordinated units, the effect of the dilutive units would be anti-dilutive to the per unit calculation. Therefore, the weighted average units outstanding are the same for basic and dilutive net loss per unit for those periods. The weighted average units that were not included in the computation of diluted per unit amounts were 2,081 and 140,100 for the three months ended March 31, 2015 and 2014, respectively.	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 years ended December 31, 2014, 2013 and 2012 (in thousands, except per unit data): Year Ended December 31, 2014 (1) Year Ended December 31, 2013 Year Ended December 31, 2012 Net loss $ (37,731 ) $ (15,970 ) $ (4,488 ) Series A Preferred Unit fair value adjustment (2) (4,596 ) (37 ) — Series A Preferred Unit in-kind distribution (534 ) (1,633 ) — General partner Unit in-kind distribution (207 ) — — Net loss from January 1, 2012 through November 6, 2012 — — 260 Net loss attributable to Holdings (6,409 ) — — Net loss attributable to partners $ (36,659 ) $ (17,640 ) $ (4,228 ) General partner's interest (3) (693 ) (319 ) — Limited partners' Class B Convertible interest (3) (7,436 ) — — Limited partners' interest (2) Common (20,175 ) (8,683 ) (2,072 ) Subordinated (8,355 ) (8,638 ) (2,071 ) ____________________________________________________________________________ ( 1) We calculate historical earnings per unit with retrospective earnings or losses of a transferred business before the date of the 2015 Holdings acquisition allocated entirely to the General Partner. The previously reported earnings per unit of the limited partners did not change as a result of the 2015 Holdings acquisition. (2) The valuation adjustment to maximum redemption value of the Series A Preferred Unit in-kind distribution increased the net loss attributable to partners for the years ended December 31, 2014 and 2013 in the calculation of earnings per unit (See Note 11) . (3) G eneral Partner's and limited partners’ interests are calculated based on the allocation of net losses for the period, net of the allocation of Series A Preferred Unit in-kind distributions, Series A Preferred Unit fair value adjustments and General Partner unit in-kind distributions. The Class B Convertible Unit interest is calculated based on the allocation of only net losses for the period. Common Units Year Ended December 31, 2014 Year Ended December 31, 2013 Year Ended December 31, 2012 Interest in net loss $ (20,175 ) $ (8,683 ) $ (2,072 ) Effect of dilutive units - numerator (1) — — — Dilutive interest in net loss $ (20,175 ) $ (8,683 ) $ (2,072 ) Weighted-average units - basic 21,641,635 12,224,997 12,213,713 Effect of dilutive units - denominator (1) — — — Weighted-average units - dilutive 21,641,635 12,224,997 12,213,713 Basic and diluted net loss per common unit $ (0.93 ) $ (0.71 ) $ (0.17 ) Subordinated Units Year Ended December 31, 2014 Year Ended December 31, 2013 Year Ended December 31, 2012 Interest in net loss $ (8,355 ) $ (8,638 ) $ (2,071 ) Effect of dilutive units - numerator (1) — — — Dilutive interest in net loss $ (8,355 ) $ (8,638 ) $ (2,071 ) Weighted-average units - basic 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 Basic and diluted net loss per subordinated unit $ (0.68 ) $ (0.71 ) $ (0.17 ) ____________________________________________________________________________ (1) Because we had a net loss for all periods for common units and the subordinated units, the effect of the dilutive units would be anti-dilutive to the per unit calculation. Therefore, the weighted average units outstanding are the same for basic and dilutive net loss per unit for those periods. The weighted average units that were not included in the computation of diluted per unit amounts were 184,417 and 10,092 and unvested awards granted under our LTIP for the year ended December 31, 2014 and 2013, respectively, and 1,213,257 Series A Preferred Units for the year ended December 31, 2013.
Distributions Made to Limited Partners and General Partner		The following table represents our distribution declared for the quarter ended December 31, 2014 and distributions paid for the previous periods (in thousands, except per unit data): Distributions Attributable to the Per Unit Limited Partners Payment Date Quarter Ended Distribution Common Subordinated General Partner Total 2014 February 13, 2015 December 31, 2014 $ 0.40 (1) $ 9,520 $ 3,432 (3) $ 416 $ 13,368 November 14, 2014 September 30, 2014 0.40 (1) 9,520 — 413 9,933 August 14, 2014 June 30, 2014 0.40 9,399 4,886 290 14,575 May 15, 2014 March 31, 2014 0.40 8,586 4,886 290 13,762 2013 February 14, 2014 December 31, 2013 0.40 8,581 4,885 289 13,755 November 14, 2013 September 30, 2013 0.40 4,888 4,885 214 9,987 August 14, 2013 June 30, 2013 0.40 4,890 4,886 210 9,986 May 15, 2013 March 31, 2013 0.40 4,888 4,886 199 9,973 2012 February 14, 2013 December 31, 2012 0.24 (2) 2,931 2,931 120 5,982 ____________________________________________________________________________ (1) The common unit distribution in the table above includes the distribution payment to the Series A Preferred unitholders for their Series A Preferred Units converted into common units or to the units that vested as part of our LTIP (as defined below) as a result of the Holdings Transaction (See Notes 1, 11 and 14). (2) Per unit distribution of $0.24 corresponds to the minimum quarterly distribution of $0.40 per unit, or $1.60 on an annualized basis, pro-rated for the portion of the quarter following the closing of our IPO on November 7, 2012. (3) Holdings waived the requirement that any distribution owed to it for the fourth quarter be paid within 45 days of the end of the quarter. We expect to pay a distribution of $0.28 on 12,213,713 of our Subordinated Units in conjunction with the filing of this Form 10-K.
Schedule of Paid In-Kind Distributions		The following table represents the PIK distribution earned on the Class B Convertible Units for periods after August 4, 2014 and ended December 31, 2014 (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 In-Kind Class B Convertible Distributions (1) In-Kind Unit to General Partner In-Kind General Partner Distribution Value (1) 2014 February 13, 2015 December 31, 2014 $ 0.3257 260,558 $ 4,143 5,318 $ 85 November 14, 2014 September 30, 2014 $ 0.3257 256,078 $ 5,467 5,226 $ 112 ____________________________________________________________________________ (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. The following table represents the paid in-kind (“PIK”) distribution from the date of our IPO through August 4, 2014, the date on which all outstanding Series A Preferred Units were converted to common units (in thousands, except per unit and in-kind distribution units): Payment Date Attributable to the Quarter Ended (1) Per Unit Distribution In-Kind Series A Holders In-Kind Series A Distributions (2) In-Kind Unit to General Partner In-Kind General Partner Distribution Value (2) 2014 May 15, 2014 March 31, 2014 $ 0.40 31,513 $ 534 643 $ 11 2013 February 14, 2014 December 31, 2013 $ 0.40 30,971 $ 558 632 $ 11 November 14, 2013 September 30, 2013 0.40 30,439 511 621 10 August 14, 2013 June 30, 2013 0.35 (3) 22,276 512 454 10 August 14, 2013 June 30, 2013 0.20 (4) 2,199 51 45 1 ____________________________________________________________________________ (1) As a result of the conversion, the Series A Preferred Unit holders (and the corresponding General Partner units) did not receive a PIK distribution for the quarters ended June 30, 2014 or September 30, 2014, but received a cash distribution on the converted common units. (2) The fair value was calculated as required, based on the common unit price at the quarter end date for the period attributable to the distribution, multiplied by the number of units distributed. (3) Per unit distribution of $0.35 corresponds to the minimum quarterly distribution of $0.40 per unit, or $1.60 on an annualized basis, pro-rated for the portion of the quarter following the issuance of 1,466,325 Series A Preferred Units and 29,925 general partner units on April 12, 2013. (4) Per unit distribution of $0.20 corresponds to the minimum quarterly distribution of $0.40 per unit, or $1.60 on an annualized basis, pro-rated for the portion of the quarter following the issuance of 248,675 Series A Preferred Units and 5,075 general partner units on May 15, 2013.
Distributions Made to Limited Partner, by Distribution [Table Text Block]	The following table represents the paid in-kind (“PIK”) distribution declared in 2014 through August 4, 2014, the date on which all outstanding Series A Preferred Units were converted to common units (in thousands, except per unit and in-kind distribution units): Payment Date Attributable to the Quarter Ended (1) Per Unit Distribution In-Kind Series A In-Kind Series A Distributions (2) In-Kind Unit to General Partner In-Kind General Partner Distribution Value (2) 2014 May 15, 2014 March 31, 2014 $ 0.40 31,513 $ 534 643 $ 11 (1) As a result of the conversion, the Series A Preferred Unit holders (and the corresponding General Partner units) ceased receiving PIK distributions effective with the quarter ended June 30, 2014, but received a cash distribution on the converted common units. (2) 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.

FINANCIAL INSTRUMENTS (Tables)

FINANCIAL INSTRUMENTS (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Derivatives
Schedule of the fair value of the interest rate cap and interest rate swap liabilities	The fair values of our interest rate derivatives were as follows (in thousands): r Significant Other Observable Inputs (Level 2) Fair Value Measurement as of March 31, 2015 December 31, 2014 Current interest rate derivative assets $ 13 $ 27 Non-current interest rate derivative assets $ 10 $ 27 Current interest rate derivative (liabilities) $ (202 ) $ (175 ) Non-current interest rate derivative (liabilities) $ (37 ) $ (39 ) Total interest rate derivatives $ (216 ) $ (160 )	Our interest rate swap position was as follows (in thousands): Estimated Fair Value Notional Amount Fixed Rate Effective Date Maturity Date December 31, 2014 $ 140,000 0.327 % June 30, 2014 June 30, 2015 $ (97 ) 50,000 1.198 % September 30, 2014 June 30, 2016 (59 ) 50,000 1.196 % September 30, 2014 June 30, 2016 (58 ) $ (214 ) In December 2014, we entered into an interest rate cap contract for $20.0 million notional value, effective December 31, 2014, with a maturity date of December 31, 2016. The contract effectively caps our LIBOR-based interest rate on that portion of debt at 1.5% . We did not designate the interest rate cap as a hedging instrument 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. 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 December 31, 2014 December 31, 2013 Current interest rate derivative assets $ 27 $ — Non-current interest rate derivative assets $ 27 $ — Current interest rate derivative (liabilities) $ (175 ) $ (263 ) Non-current interest rate derivative (liabilities) $ (39 ) $ — Total interest rate derivatives $ (160 ) $ (263 )
Schedule of Derivative Instruments, Effect on Other Comprehensive Income (Loss) [Table Text Block]	The effect of the interest rate swap designated as a cash flow hedge in our statements of changes in partners’ capital and comprehensive loss was as follows (in thousands): Three Months Ended March 31, 2015 2014 Change in value recognized in other comprehensive loss - effective portion $ — $ (11 ) Loss reclassified from accumulated other comprehensive loss to interest expense — 115
Schedule of cash flow hedges effect on partners' capital and comprehensive income (loss)		The effect of the interest rate swap designated as a cash flow hedge in our statements of changes in partners’ capital and members’ equity and comprehensive loss was as follows (in thousands): Year Ended December 31, 2014 2013 2012 Change in value recognized in other comprehensive loss - effective portion $ (11 ) $ (148 ) $ (745 ) Loss reclassified from accumulated other comprehensive loss to interest expense $ 221 $ 415 $ 268
Schedule of amounts recognized in the statement of operations	The effect of offsetting on our balance sheets was as follows (in thousands): March 31, 2015 December 31, 2014 Other Current Assets Other Current Liabilities Other Current Assets Other Current Liabilities Gross amounts of recognized assets (liabilities) $ — $ — $ 112 $ — Gross amounts offset on the balance sheets — — — — Net amount $ — $ — $ 112 $ — The realized and unrealized gain/loss on these derivatives, recognized in revenues in our statements of operations, was as follows (in thousands): Three Months Ended March 31, 2015 2014 Realized gain (loss) on commodity swap derivatives $ 125 $ (1,169 ) Unrealized gain (loss) on commodity swap derivatives (111 ) 44
Schedule of offsetting assets and liabilities		The effect of offsetting on our balance sheets were as follows (in thousands): December 31, 2014 December 31, 2013 Other Current Assets Other Current Liabilities Other Current Assets Other Current Liabilities Gross amounts of recognized assets (liabilities) $ 112 $ — $ 140 $ (20 ) Gross amounts offset on the balance sheets — — (20 ) 20 Net amount 112 — 120 —
Schedule of Interest Rate Derivatives [Table Text Block]	These interest rate swaps are not designated as cash flow hedges and as a result, changes in the fair value of the interest rate swaps are recognized in interest expense immediately. Our interest rate swap position was as follows (in thousands): Estimated Fair Value Notional Amount Fixed Rate Effective Date Maturity Date March 31, 2015 $ 140,000 0.327 % June 30, 2014 June 30, 2015 $ (51 ) 50,000 1.198 % September 30, 2014 June 30, 2016 (94 ) 50,000 1.196 % September 30, 2014 June 30, 2016 (94 ) $ (239 )
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	The realized and unrealized amounts recognized in interest expense associated with derivatives that are not designated as hedging instruments were as follows (in thousands): Three Months Ended March 31, 2015 2014 Unrealized loss on interest rate derivatives $ 56 $ 12 Realized loss on interest rate derivatives 104 27
Interest rate cap contract
Derivatives
Schedule of amounts recognized in the statement of operations		The realized and unrealized amounts recognized in interest expense associated with derivatives that are not designated as hedging instruments were as follows (in thousands): Year Ended December 31, 2014 2013 2012 Unrealized loss on interest rate derivatives $ 160 $ — $ 141 Realized loss on interest rate derivatives $ 316 $ 108 $ 82
Commodity Swaps
Derivatives
Schedule of amounts recognized in the statement of operations		The realized and unrealized gain/loss on these derivatives, recognized in revenues in our statements of operations, were as follows (in thousands): Year ended December 31, 2014 2013 2012 Realized (loss) gain on commodity swap derivatives $ 347 $ (659 ) $ (12 ) Unrealized (loss) gain on commodity swap derivatives (8 ) 120 —

LONG-LIVED ASSETS (Tables)

LONG-LIVED ASSETS (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Schedule of property, plant and equipment	Property, plant and equipment consisted of the following (in thousands): Estimated Useful Life (yrs) March 31, 2015 December 31, 2014 Pipelines 15-30 $ 503,888 $ 488,592 Gas processing, treating and other plants 15 532,538 515,080 Compressors 7-15 64,856 62,741 Rights of way and easements 15 37,263 37,238 Furniture, fixtures and equipment 5 3,735 3,671 Capital lease vehicles 3-5 2,284 2,076 Total property, plant and equipment 1,144,564 1,109,398 Accumulated depreciation and amortization (159,252 ) (142,234 ) Total 985,312 967,164 Construction in progress 51,319 63,858 Land and other 24,002 27,548 Property, plant and equipment, net $ 1,060,633 $ 1,058,570	Property, plant and equipment consist of the following (in thousands): Estimated Useful Life As of December 31, 2014 2013 Pipelines 15-30 $ 488,592 $ 344,721 Gas processing, treating and other plants 15 515,080 254,133 Compressors 7-15 62,741 20,030 Rights of way and easements 15 37,238 20,729 Furniture, fixtures and equipment 5 3,671 3,347 Capital lease vehicles 3-5 2,076 1,396 Total property, plant and equipment 1,109,398 644,356 Accumulated depreciation and amortization (142,234 ) (79,908 ) Total 967,164 564,448 Construction in progress 63,858 6,039 Land and other 27,548 5,308 Property, plant and equipment, net $ 1,058,570 $ 575,795

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Debt Disclosure [Abstract]
Schedule of long-term debt	Our outstanding debt and related information at March 31, 2015 and December 31, 2014 are as follows (in thousands): March 31, 2015 December 31, 2014 Revolving credit facility due 2019 $ 65,000 $ 30,000 Term loans (including OID of $2.1 million) due 2021 444,592 445,629 Total long-term debt (including current portion) 509,592 475,629 Current portion of long-term debt $ (4,500 ) $ (4,500 ) Total long-term debt $ 505,092 $ 471,129 Outstanding letters of credit $ 20,830 $ 30,130 Remaining unused borrowings $ 114,170 $ 139,870 Three Months Ended March 31, 2015 2014 Weighted average interest rate 5.1 % 4.6 % Average outstanding borrowings $ 512,093 $ 192,403 Maximum borrowings $ 522,750 $ 267,300	Our outstanding debt and related information at December 31, 2014 and December 31, 2013 are as follows (in thousands): As of December 31, 2014 2013 Credit facility due 2019 $ 30,000 $ 267,300 Term loans (including OID of $2.1 million) due 2021 445,629 — Total long-term debt (including current portion) $ 475,629 $ 267,300 Current portion of long-term debt $ (4,500 ) $ — Total long-term debt $ 471,129 $ 267,300 Outstanding letters of credit $ 30,130 $ 31,260 Remaining unused borrowings $ 139,870 $ 69 Year Ended December 31, 2014 2013 Weighted average interest rate 4.6 % 4.4 % Average outstanding borrowings $ 308,670 $ 243,920 Maximum borrowings $ 491,875 $ 267,300 Total 2015 2016 2017 2018 2019 Thereafter Maturity Long-term debt $ 475,629 $ 4,500 $ 4,500 $ 4,500 $ 4,500 $ 34,500 $ 423,129

COMMITMENTS AND CONTINGENT LI36

COMMITMENTS AND CONTINGENT LIABILITIES (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Schedule of Capital Lease Obligations [Table Text Block]	The capital lease obligation amounts included on the balance sheets were as follows (in thousands): March 31, 2015 December 31, 2014 Other current liabilities $ 451 $ 455 Other non-current liabilities 649 578 Total $ 1,100 $ 1,033	The capital lease obligation amounts included on the balance sheets were as follows (in thousands): December 31, 2014 December 31, 2013 Other current liabilities $ 455 $ 481 Other non-current liabilities 578 427 Total $ 1,033 $ 908
Schedule of future minimum annual rental commitments under capital and operating leases		Future minimum annual rental commitments under our capital and operating leases at December 31, 2014 were as follows (in thousands): Years Ending December 31, Capital Leases Operating Leases 2015 $ 468 $ 1,170 2016 283 1,156 2017 212 1,122 2018 95 1,055 2019 3 1,080 Thereafter — $ 5,775 Total future payments 1,061 $ 11,358 Less: Imputed interest $ (35 ) Future lease payments $ 1,026

TRANSACTIONS WITH RELATED PAR37

TRANSACTIONS WITH RELATED PARTIES (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Related Party Transactions [Abstract]
Schedule of Related Party Transactions [Table Text Block]	We incurred fees and expenses related to the services from our affiliated directors as follows (in thousands): Three Months Ended March 31, 2015 2014 Charlesbank $ 14 $ — EIG 16 — Tailwater 16 — Total fees and expenses paid for director services to affiliated entities $ 46 $ — We incurred expenses related to these reimbursements as follows (in thousands): Three Months Ended March 31, 2015 2014 Reimbursements included in general and administrative expenses $ 3,134 $ 3,475 Reimbursements included in operations and maintenance expenses 4,781 3,943 Total reimbursements to our General Partner and its affiliates $ 7,915 $ 7,418	We incurred fees and expenses related to the services from our affiliated directors as follows (in thousands): Year Ended December 31, 2014 2013 2012 Charlesbank $ 340 $ 463 $ — EIG 20 — — Tailwater 20 — — Total fees and expenses paid for director services to affiliated entities $ 380 $ 463 $ — We incurred expenses related to these reimbursements as follows (in thousands): Year Ended December 31, 2014 2013 2012 Reimbursements included in general and administrative expenses $ 10,944 $ 9,364 $ — Reimbursements included in operations and maintenance expenses 16,093 13,264 — Total reimbursements to our General Partner and its affiliates $ 27,037 $ 22,628 $ —

PARTNERS' CAPITAL AND MEMBERS38

PARTNERS' CAPITAL AND MEMBERS' EQUITY - (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Partners' Capital [Abstract]
Schedule of Stockholders Equity [Table Text Block]	Our units outstanding as of March 31, 2015 are as follows (in units): Owned by Parent Partners’ Capital Public Class B General Common Common Convertible Subordinated Partner Units outstanding as of December 31, 2014 21,684,543 2,116,400 14,889,078 12,213,713 1,038,852 In-kind distributions and general partner issuances to maintain 2.0% ownership — — 260,558 — 5,318 Units outstanding as of March 31, 2015 21,684,543 2,116,400 15,149,636 12,213,713 1,044,170	Our units outstanding as of December 31, 2014 are as follows (in units): Partners’ Capital Owned By Parent Series A Public Holdings Class B General Preferred Common Common Convertible Subordinated Partner Units outstanding as of December 31, 2013 1,769,915 10,390,272 — — 12,213,713 534,638 Issuance of common units — 9,200,000 — — — 187,755 Holdings Transaction — — 1,863,713 — — — Series A Convertible preferred conversion to common units (1,832,399 ) 1,762,951 252,687 — — — Issuance of Class B Convertible Units — — — 14,633,000 — — Vesting of LTIP units, net — 331,320 — — — — In-kind distributions and general partner issuances to maintain 2.0% ownership 62,484 — — 256,078 — 316,459 Units outstanding as of December 31, 2014 — 21,684,543 2,116,400 14,889,078 12,213,713 1,038,852

INCENTIVE COMPENSATION (Tables)

INCENTIVE COMPENSATION (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of information regarding the Incentive Plan unit activity	The following table summarizes information regarding awards of units granted under the LTIP: Units Weighted-Average Fair Unvested - December 31, 2014 470,750 $ 20.45 Granted units 372,283 $ 13.80 Forfeited units (17,514 ) $ 20.69 Unvested - March 31, 2015 825,519 $ 18.15	The following table summarizes information regarding awards of units granted under the LTIP: Units Weighted-Average Fair Value at Grant Date Unvested - November 7, 2012 — $ — Granted units 146,000 23.01 Forfeited units (1,500 ) 23.01 Vested units — — Unvested - December 31, 2012 144,500 $ 23.01 Granted units 112,179 21.96 Forfeited units (20,700 ) 22.09 Units recaptured for tax withholdings (13,034 ) 23.01 Vested units (40,272 ) 22.30 Unvested - December 31, 2013 182,673 $ 22.55 Granted units 787,321 19.82 Forfeited units (1,050 ) 23.01 Units recaptured for tax withholdings (159,500 ) 17.06 Vested units (338,694 ) 17.45 Unvested - December 31, 2014 470,750 $ 20.45
Schedule of 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): Year Ended December 31, 2014 2013 2012 Unit-based compensation $ 10,074 (1) $ 2,186 $ 630 ____________________________________________________________________________ (1) This amount includes $7.2 million related to the accelerated vesting of the LTIP awards and $0.1 million related to the vesting of the Southcross Energy LLC equity equivalent units as a result of the change in control that took place on August 4, 2014.
Schedule of Employer's Matching Contributions	The following table summarizes information regarding contributions and the expense recognized for the matching contributions, which is included in general and administrative expense on our statements of operations (in thousands): Three Months Ended March 31, 2015 2014 Matching contributions expensed for employee savings plan $ 181 $ 356	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): Year Ended December 31, 2014 2013 2012 Matching contributions expensed for employee savings plan $ 927 $ 628 $ 512
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Table Text Block]	The following table summarizes information regarding recognized compensation expense, which is included in general and administrative and operations and maintenance expense on our statements of operations (in thousands): Three Months Ended March 31, 2015 2014 Unit-based compensation $ 813 $ 529

REVENUES (Tables)

REVENUES (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Revenues [Abstract]
Schedule of revenues by category	We had revenues consisting of the following categories (in thousands): Three Months Ended March 31, 2015 2014 Sales of natural gas $ 112,786 $ 145,358 Sales of NGLs and condensate 37,183 51,874 Transportation, gathering and processing fees 35,053 16,115 Other 916 244 Total revenues $ 185,938 $ 213,591	We had revenues consisting of the following categories (in thousands): Year ended December 31, 2014 2013 2012 Sales of natural gas $ 530,947 $ 405,206 $ 325,421 Sales of NGLs and condensate 226,218 169,523 124,139 Transportation, gathering and processing fees 90,807 59,392 46,113 Other 541 601 456 Total revenues $ 848,513 $ 634,722 $ 496,129

EQUITY IN JOINT VENTURES (Table

EQUITY IN JOINT VENTURES (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments and Joint Ventures Disclosure [Text Block]	INVESTMENTS IN JOINT VENTURES Assets acquired through the TexStar Rich Gas System Transaction include equity interests in three joint ventures. During 2012, a subsidiary of TexStar and a company subsequently acquired by Atlas Pipeline Partners, L.P. (“Atlas”) formed T2 Eagle Ford Gathering Company LLC (“T2 Eagle Ford”), T2 LaSalle Gathering Company LLC (“T2 LaSalle”) and T2 EF Cogeneration Holdings LLC (“T2 Cogen”, and collectively “T2 Rich Gas System”) to construct and operate a pipeline and cogeneration facility located in South Texas. During 2015, Atlas was acquired by Targa Pipeline Partners LP, which is now our joint venture partner. The Partnership indirectly has a 50% interest in T2 Eagle Ford, a 50% interest in T2 Cogen and a 25% interest in T2 LaSalle. The joint ventures’ summarized financial data from their statements of operations for the three months ended March 31, 2015 is as follows (in thousands): Three Months Ended March 31, 2015 T2 Eagle Ford T2 Cogen T2 LaSalle Revenue $ 921 $ 1,662 $ 379 Net loss (4,997 ) (1,361 ) (1,520 ) The Partnership’s equity in losses of joint venture investments is comprised of the following for the three months ended March 31, 2015 (in thousands): Three Months Ended March 31, 2015 T2 Eagle Ford $ (2,491 ) T2 Cogen (681 ) T2 LaSalle (380 ) Equity in losses of joint venture investments $ (3,552 ) The Partnership’s investments in joint ventures is comprised of the following as of March 31, 2015 (in thousands): March 31, 2015 T2 Eagle Ford $ 107,237 T2 Cogen 19,444 T2 LaSalle 18,994 Investments in joint ventures $ 145,675	INVESTMENTS IN JOINT VENTURES Assets acquired through the TexStar Rich Gas System Transaction include equity interests in three joint ventures. During 2012, a subsidiary of TexStar and a company subsequently acquired by Atlas Pipeline Partners, L.P. formed T2 Eagle Ford Gathering Company LLC (“T2 Eagle Ford”), T2 LaSalle Gathering Company LLC (“T2 LaSalle”) and T2 EF Cogeneration Holdings LLC (“T2 Cogen”) to construct and operate a pipeline and cogeneration facility located in South Texas. The Partnership indirectly has a 50% interest in T2 Eagle Ford, a 50% interest in T2 Cogen and a 25% interest in T2 LaSalle. The joint ventures’ summarized financial data from their statements of operations since we obtained our equity interests in the joint ventures on August 4, 2014 is as follows (in thousands): Year Ended December 31, 2014 T2 Eagle Ford T2 Cogen T2 LaSalle Revenue $ 3,537 $ 2,517 $ 1,163 Net loss (6,277 ) (4,281 ) (1,876 ) The Partnership’s equity in losses of joint venture investments is comprised of the following for the year ended December 31, 2014 (in thousands): Year Ended December 31, 2014 T2 Eagle Ford $ (3,656 ) T2 Cogen (2,141 ) T2 LaSalle (699 ) Equity in losses of joint venture investments $ (6,496 ) The Partnership’s investments in joint ventures is comprised of the following as of December 31, 2014 (in thousands): December 31, 2014 T2 Eagle Ford $ 108,185 T2 Cogen 19,615 T2 LaSalle 19,298 Investments in joint ventures $ 147,098 The joint ventures’ summarized financial data from their balance sheets as of December 31, 2014 is as follows (in thousands): Year Ended December 31, 2014 T2 Cogen T2 Eagle Ford T2 LaSalle Current assets $ 8,923 $ 4,173 $ 904 Property, plant and equipment, net 38,851 216,863 77,189 Total assets 47,774 221,036 78,093 Total liabilities 8,547 3,915 904 Total equity 39,227 217,121 77,189 Total liabilities and equity $ 47,774 $ 221,036 $ 78,093 The joint ventures’ summarized financial data from their statements of operations since we obtained our equity interests in the joint ventures on August 4, 2014 is as follows (in thousands): Year Ended December 31, 2014 T2 Eagle Ford T2 Cogen T2 LaSalle Revenue $ 3,537 $ 2,517 $ 1,163 Net loss (6,277 ) (4,281 ) (1,876 ) The Partnership’s equity in losses of joint venture investments is comprised of the following for the year ended December 31, 2014 (in thousands): Year Ended December 31, 2014 T2 Eagle Ford $ (3,656 ) T2 Cogen (2,141 ) T2 LaSalle (699 ) Equity in losses of joint venture investments $ (6,496 ) The Partnership’s investments in joint ventures is comprised of the following as of December 31, 2014 (in thousands): December 31, 2014 T2 Eagle Ford $ 108,185 T2 Cogen 19,615 T2 LaSalle 19,298 Investments in joint ventures $ 147,098 The joint ventures’ summarized financial data from their balance sheets as of December 31, 2014 is as follows (in thousands): Year Ended December 31, 2014 T2 Cogen T2 Eagle Ford T2 LaSalle Current assets $ 8,923 $ 4,173 $ 904 Property, plant and equipment, net 38,851 216,863 77,189 Total assets 47,774 221,036 78,093 Total liabilities 8,547 3,915 904 Total equity 39,227 217,121 77,189 Total liabilities and equity $ 47,774 $ 221,036 $ 78,093
Equity Method Investments [Table Text Block]	The joint ventures’ summarized financial data from their statements of operations for the three months ended March 31, 2015 is as follows (in thousands): Three Months Ended March 31, 2015 T2 Eagle Ford T2 Cogen T2 LaSalle Revenue $ 921 $ 1,662 $ 379 Net loss (4,997 ) (1,361 ) (1,520 ) The Partnership’s equity in losses of joint venture investments is comprised of the following for the three months ended March 31, 2015 (in thousands): Three Months Ended March 31, 2015 T2 Eagle Ford $ (2,491 ) T2 Cogen (681 ) T2 LaSalle (380 ) Equity in losses of joint venture investments $ (3,552 ) The Partnership’s investments in joint ventures is comprised of the following as of March 31, 2015 (in thousands): March 31, 2015 T2 Eagle Ford $ 107,237 T2 Cogen 19,444 T2 LaSalle 18,994 Investments in joint ventures $ 145,675

CONCENTRATION OF CREDIT RISK 42

CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Risks and Uncertainties [Abstract]
Schedules of Concentration of Risk, Consolidated Revenue	Our top ten customers for the three months ended March 31, 2015 and 2014 represent the following percentages of consolidated revenue: Three Months Ended March 31, 2015 2014 Top ten customers 60.1 % 64.6 % The percentage of total consolidated revenue for each customer that exceeded 10% of total revenues for the three months ended March 31, 2015 and 2014 was as follows: Three Months Ended March 31, 2015 2014 Trafigura Trading LLC 10.9 % 12.2 %	Our top ten customers for the years ended December 31, 2014, 2013 and 2012 represent the following percentages of consolidated revenue: Year Ended December 31, 2014 2013 2012 Top ten customers 63.4 % 59.7 % 65.5 % The percentage of total consolidated revenue for each customer that exceeded 10% of total revenues for the years ended December 31, 2014, 2013 and 2012 was as follows: Year Ended December 31, 2014 2013 2012 Trafigura AG 13.6 % 11.7 % 11.0 % Formosa Hydrocarbons Co., Inc. (a),(b) (a),(b) 24.3 %

SUPPLEMENTAL CASH FLOW INFORM43

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	Three Months Ended March 31, 2015 2014 Supplemental Disclosures: Cash paid for interest, net of amounts capitalized $ 6,841 $ 2,776 Cash paid for taxes, net of refunds received — 23 Supplemental disclosures of non-cash investing and financing activities: Accounts payable related to capital expenditures 22,793 1,628 Change in value recognized in other comprehensive loss — 11 Capital lease obligations 207 307 Accrued distribution equivalent rights on LTIP units 342 76 Class B Convertible unit in-kind distributions 3,712 —	SUPPLEMENTAL CASH FLOW INFORMATION Year Ended December 31, 2014 2013 2012 Supplemental Disclosures: Cash paid for interest $ 16,206 $ 13,043 $ 10,552 Cash received for tax refunds 205 95 315 Supplemental schedule of non-cash investing and financing activities: Accounts payable related to capital expenditures 29,645 4,946 40,707 Change in value recognized in other comprehensive income 11 148 745 Capital lease obligation 708 1,396 — Accrued distribution equivalent rights on the LTIP units 167 279 — Series A Convertible preferred unit in-kind distributions and fair value adjustments 5,129 — — Class B Convertible unit issuance, net 324,413 — — Class B Convertible unit in-kind distributions 9,610 — — Consideration paid in excess of purchase price for the TexStar Rich Gas System 98,625 — — Settlement of EEU liability by Southcross Energy LLC 1,151 — — Non-cash capitalized interest for 2015 Holdings Acquisition 323 — — Consolidation of Valley Wells' net assets 33,165 — —
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Table Text Block]	Changes in deferred financing costs are as follows (in thousands): 2015 2014 Deferred financing costs, January 1 $ 16,602 $ 5,237 Capitalization of deferred financing costs (1) 6 156 Amortization of deferred financing costs (737 ) (337 ) Deferred financing costs, March 31 $ 15,871 $ 5,056

SUPPLEMENTAL SELECTED QUARTER44

SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
SCHEDULE OF SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)	The following presents a summary of selected quarterly financial information (in thousands, except per unit data): Quarters ended 2014 March 31 June 30 September 30 (1) December 31 (1) Revenues $ 213,591 $ 195,063 $ 212,676 $ 227,182 Gross operating margin 27,188 26,237 32,115 41,841 (Loss) income from operations 1,692 (1,134 ) (15,658 ) 1,872 Net loss (1,289 ) (2,961 ) (26,032 ) (2) (7,448 ) Basic and diluted net loss per common unit (0.06 ) (0.34 ) (0.49 ) 0.05 Basic and diluted net loss per subordinated unit (0.06 ) (0.11 ) (0.49 ) 0.05 Quarters ended 2013 March 31 June 30 September 30 December 31 Revenues $ 144,250 $ 154,703 $ 160,629 $ 175,140 Gross operating margin 18,863 21,296 25,213 28,174 (Loss) income from operations (4,317 ) (2,831 ) (357 ) 4,510 Net (loss) income (6,382 ) (6,192 ) (4,069 ) 673 Basic net (loss) income per common unit (0.26 ) (0.65 ) 0.19 (0.01 ) Diluted net loss per common unit (0.26 ) (0.65 ) (0.14 ) (0.01 ) Basic and diluted net loss per subordinated unit (0.26 ) (0.27 ) (0.19 ) (0.01 ) ____________________________________________________________________________ (1) Due to the common control aspects in the 2015 Holdings Acquisition, 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 the Compression Assets for all periods ending after August 4, 2014, the date of the Holdings Transaction. (2) See Note 4.

ORGANIZATION AND DESCRIPTION 45

ORGANIZATION AND DESCRIPTION OF BUSINESS (Details) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2015USD ($)segmentplant	Dec. 31, 2014segmentplantmi
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of gas processing plants		4
Number of fractionation plants	2	2
Pipeline, length owned | mi		3,041
Number of reportable segments | segment	1	1
Other Additional Capital | $	$ 25

BASIS OF PRESENTATION (Details)

BASIS OF PRESENTATION (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2014
Accounting Policies [Abstract]
Asset Impairment Charges		$ 1,556,000	$ 0	$ 0
Basis of Presentation
Ownership interest in consolidated subsidiaries (as a percent)	57.40%	100.00%			57.40%
Long-Lived Assets
Expected useful lives of long-term supply and gas gathering contracts	30 years	30 years
Accounts Receivable
Allowance for Doubtful Accounts Receivable, Current		$ 0	0
Asset Retirement Obligation [Abstract]
Asset retirement obligation		$ 500,000	$ 0

BASIS OF PRESENTATION BASIS O47

BASIS OF PRESENTATION BASIS OF PRESENTATION - Interest Expense (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Total interest costs	$ 7,800	$ 3,072	$ 18,649	$ 14,047	$ 12,035
Capitalized interest included in property, plant and equipment, net	(302)	(99)	(3,087)	(1,457)	(6,268)
Interest expense	$ 7,498	$ 2,973	$ 15,562	$ 12,590	$ 5,767

BASIS OF PRESENTATION BASIS O48

BASIS OF PRESENTATION BASIS OF PRESENTATION - Deferred Financing Costs (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Write-off of Deferred Financing Costs			$ 2,300
Deferred Financing Costs [Roll Forward]
Deferred financing costs, beginning balance	$ 16,602	$ 5,237	5,237	$ 4,385
Capitalization of deferred financing costs	6	156	15,659	2,139
Amortization of deferred financing costs	(825)	(337)	(4,192)	(1,287)	$ (1,183)
Deferred financing costs, ending balance	$ 15,871	$ 5,056	$ 16,602	$ 5,237	$ 4,385

LIQUIDITY CONSIDERATIONS AND 49

LIQUIDITY CONSIDERATIONS AND EQUITY OFFERINGS (Details)	Apr. 12, 2013USD ($)item$ / sharesshares	Feb. 28, 2014	Dec. 31, 2012USD ($)	Mar. 31, 2015USD ($)	Mar. 31, 2014USD ($)$ / shares	Dec. 31, 2014USD ($)shares	Dec. 31, 2013USD ($)	Dec. 31, 2012USD ($)	Aug. 04, 2014USD ($)	Mar. 13, 2014USD ($)	Nov. 29, 2013USD ($)	Mar. 27, 2013USD ($)	Mar. 25, 2013USD ($)	Nov. 07, 2012USD ($)
Schedule of Capitalization, Long-term Debt [Line Items]
Amortization of financing costs				$ (825,000)	$ (337,000)	$ (4,192,000)	$ (1,287,000)	$ (1,183,000)
Proceeds from issuance under public offering								$ 187,764,000
Public offering, amount authorized											$ 675,000,000
Contributions from general partner			$ 262,826,000	$ 0	$ (3,115,000)	11,316,000
Additional capital contributions						25,000,000
Senior Secured Credit Facility [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Maximum borrowing capacity						$ 350,000,000				$ 350,000,000		$ 250,000,000	$ 350,000,000
Letter of Credit [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Maximum borrowing capacity	$ 75,000,000								$ 75,000,000					$ 200,000,000
Series A Convertible Preferred Units [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Number of succeeding quarters relating to estimated quarterly distributions used for determination of conversion of preferred units | item	4
Units issued and sold | shares	1,715,000
Share price | $ / shares	$ 22.86				$ 22.86
Proceeds from issuance of units	$ 39,200,000
Series A Convertible Preferred Units [Member] | Senior Secured Credit Facility [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Total capital infusion	40,000,000
General Partner [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Units authorized for public offering | shares						187,755
Contributions from general partner			$ 6,713,000		$ 3,115,000	$ 9,991,000
Additional capital contributions	$ 800,000
Ownership interest held by limited partners (as a percent)	2.00%	2.00%
Common Units [Member] | Series A Convertible Preferred Units [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Units issued and sold | shares	1,715,000

ACQUISITIONS (Details)

ACQUISITIONS (Details)	May. 07, 2015USD ($)	Aug. 04, 2014USD ($)$ / sharesshares	Mar. 06, 2014USD ($)plant	Mar. 31, 2014USD ($)	Dec. 31, 2012USD ($)$ / shares	Mar. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)	Sep. 30, 2014USD ($)	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)$ / shares	Dec. 31, 2013USD ($)$ / shares	Sep. 30, 2013USD ($)$ / shares	Jun. 30, 2013USD ($)$ / shares	Mar. 31, 2013USD ($)$ / shares	Sep. 30, 2014USD ($)	Dec. 31, 2014USD ($)	Nov. 06, 2012USD ($)	Dec. 31, 2014USD ($)$ / sharesshares	Dec. 31, 2013USD ($)$ / shares	Dec. 31, 2012USD ($)$ / shares	Jun. 30, 2015shares	Nov. 21, 2014USD ($)
ACQUISITIONS
Payments to Acquire Businesses, Gross						$ 80,000,000									$ 80,000,000
Purchase Price - Cash
Payments to Acquire Businesses, Net of Cash Acquired						0				$ 38,636,000								$ 44,038,000	$ 0	$ 0
Fair value of identifiable assets acquired
Net identifiable assets acquired						88,800,000
number of power plants | plant			2
Contractual Agreement, Term			10 years
Shares Issued, Price Per Share | $ / shares		$ 22.17
Transaction costs associated with acquisition																		9,900,000
Unaudited Pro Forma Information
Revenue						185,938,000	$ 227,182,000	$ 212,676,000	$ 195,063,000	213,591,000	$ 175,140,000	$ 160,629,000	$ 154,703,000	$ 144,250,000				848,513,000	634,722,000	496,129,000
Net income					$ (4,228,000)	(13,905,000)	(7,448,000)	(26,032,000)	$ (2,961,000)	(1,289,000)	$ 673,000	$ (4,069,000)	$ (6,192,000)	$ (6,382,000)			$ (260,000)	(37,731,000)	(15,970,000)	(4,488,000)
Net loss attributable to common unitholders																		$ 0	0	$ (22,910,000)
Basic and diluted net loss per subordinated unit (in dollars per share) | $ / shares					$ (0.71)													$ (0.93)		$ (0.17)
Total revenue						180,549,000												$ 842,728,000
Net income						(10,751,000)												(31,322,000)
Business Combination, Consideration Transferred		$ 98,625,000																98,625,000
Revenue from Related Parties						7,447,000				0								13,267,000	0	$ 0
valley wells [Member]
Unaudited Pro Forma Information
Revenue from Related Parties						5,389,000												5,785,000
Related Party Transaction, Other Revenues from Transactions with Related Party						(3,154,000)												(6,409,000)
TexStar Rich Gas System [Member]
ACQUISITIONS
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net		404,414,000
Consideration paid in excess of purchase price for the TexStar Rich Gas System		98,625,000					98,625,000									$ 98,625,000		98,625,000
Fair value of identifiable assets acquired
Current assets		1,295,000
Property, plant and equipment		255,220,000
Noncontrolling Interest in Joint Ventures		152,050,000
Total assets acquired		408,565,000
Business Combination, Liabilities Arising from Contingencies, Amount Recognized		(102,776,000)
Net identifiable assets acquired		305,789,000
Pipelines
Fair value of identifiable assets acquired
Net identifiable assets acquired		100,000,000
Onyx Midstream LP & Onyx Pipeline Company [Member]
ACQUISITIONS
Consideration paid in excess of purchase price for the TexStar Rich Gas System						$ 0		$ 0							$ 0
Fair value of identifiable assets acquired
Current assets			$ 730,000
Property, plant and equipment			39,413,000
Total assets acquired			40,143,000
Current liabilities			(1,407,000)
Net identifiable assets acquired			38,636,000
Unaudited Pro Forma Information
Net income																4,200,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other			$ (100,000)
Texoz [Member]
ACQUISITIONS
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net																						$ 5,400,000
Fair value of identifiable assets acquired
Net identifiable assets acquired																						$ 5,400,000
Valley Wells Systems and Compression Assets [Member]
Unaudited Pro Forma Information
Net Assets							$ 77,300,000									77,300,000		77,300,000
Pro Forma [Member] | Onyx Midstream LP & Onyx Pipeline Company [Member]
Unaudited Pro Forma Information
Total revenue				$ 300,000						214,240,000						$ 1,300,000		843,376,000	639,104,000
Net income				$ 100,000						(1,397,000)								(31,400,000)	(18,306,000)
Common Units [Member]
Purchase Price - Cash
Common Stock, Shares, Issued | shares						4,500,000
Class B Convertible Units [Member]
Unaudited Pro Forma Information
Net income						$ (3,119,000)												(7,436,000)
Business Combination, Consideration Transferred		27,925,000																27,925,000
Subordinated Limited Partners [Member]
Unaudited Pro Forma Information
Net income					$ (2,071,000)	(2,513,000)				(506,000)								(8,105,000)	(7,822,000)
Net loss attributable to common unitholders						$ (2,533,000)				$ (719,000)
Basic and diluted net loss per subordinated unit (in dollars per share) | $ / shares						$ (0.21)				$ (0.06)
Business Combination, Consideration Transferred		23,308,000																23,308,000
Common Limited Partners [Member]
Unaudited Pro Forma Information
Net income					(2,072,000)	$ (4,902,000)				$ (757,000)								(15,155,000)	(7,829,000)
Net loss attributable to common unitholders					(8,683,000)	$ (4,936,000)				$ (1,045,000)								(20,175,000)		$ (2,072,000)
Basic and diluted net loss per subordinated unit (in dollars per share) | $ / shares						$ (0.21)				$ (0.06)
Business Combination, Consideration Transferred		45,420,000																45,420,000
General Partner [Member]
Unaudited Pro Forma Information
Net income					$ (85,000)	$ (217,000)				$ (26,000)								(626,000)	(319,000)
Business Combination, Consideration Transferred		$ 1,972,000																$ 1,972,000
Class B Convertible Units [Member] | Class B Convertible Units [Member]
Fair value of identifiable assets acquired
Conversion of Stock, Shares Issued | shares		14,633,000				15,149,636												14,633,000
Class B Convertible Units [Member] | Common Limited Partners [Member]
Fair value of identifiable assets acquired
Conversion of Stock, Shares Issued | shares																		0
Class B Convertible Units [Member] | General Partner [Member]
Fair value of identifiable assets acquired
Conversion of Stock, Shares Issued | shares																		0
Common Units [Member] | Pro Forma [Member] | Onyx Midstream LP & Onyx Pipeline Company [Member]
Unaudited Pro Forma Information
Net income										$ (1,115,000)								$ (20,211,000)	$ (9,934,000)
Net loss per unit - (basic and diluted) | $ / shares										$ 0								$ (0.85)	$ (0.68)
Subordinated Units [Member]
Unaudited Pro Forma Information
Basic and diluted net loss per subordinated unit (in dollars per share) | $ / shares											$ (0.01)	$ (0.19)	$ (0.27)	$ (0.26)
Subordinated Units [Member] | Pro Forma [Member] | Onyx Midstream LP & Onyx Pipeline Company [Member]
Unaudited Pro Forma Information
Net income										$ (745,000)								$ (8,373,000)	$ (9,678,000)
Net loss per unit - (basic and diluted) | $ / shares										$ 0								$ (0.69)	$ (0.79)
Subsequent Event [Member]
ACQUISITIONS
Payments to Acquire Businesses, Gross	$ 77,600,000
Purchase Price - Cash
Payments to Acquire Businesses, Net of Cash Acquired	$ 15,000,000
Subsequent Event [Member] | Common Units [Member]
Purchase Price - Cash
Common Stock, Shares, Issued | shares																					4,500,000

Transaction-Related Costs (Deta

Transaction-Related Costs (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2014
Business Combination, Separately Recognized Transactions [Line Items]
Transaction costs associated with acquisition		$ 9.9
Severance Costs		0.6
LTIP [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost	$ 7.2
Equity Equivalent Units [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost	$ 0.1	0.1
TexStar Rich Gas System [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Professional Fees		1.7
Onyx Midstream LP & Onyx Pipeline Company [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Professional Fees		$ 0.3

EARNINGS PER LIMITED PARTNER 52

EARNINGS PER LIMITED PARTNER UNIT AND DISTRIBUTIONS (Details) - Subsequent Event Type [Domain]	Apr. 12, 2013USD ($)shares	Dec. 31, 2012USD ($)$ / sharesshares	Mar. 31, 2015USD ($)item$ / sharesshares	Dec. 31, 2014USD ($)$ / sharesshares	Sep. 30, 2014USD ($)$ / sharesshares	Jun. 30, 2014USD ($)$ / shares	Mar. 31, 2014USD ($)$ / sharesshares	Dec. 31, 2013USD ($)$ / sharesshares	Sep. 30, 2013USD ($)$ / shares	Jun. 30, 2013USD ($)$ / shares	Mar. 31, 2013USD ($)$ / shares	Dec. 31, 2012USD ($)$ / shares	Nov. 06, 2012USD ($)shares	Dec. 31, 2014USD ($)item$ / sharesshares	Dec. 31, 2013USD ($)$ / sharesshares	Dec. 31, 2012USD ($)$ / sharesshares	May. 15, 2013shares
Earnings Per Unit of the Partnership
Distribution Made to Member or Limited Partner Minimum Quarterly Distributions Declared Per Unit | $ / shares			$ 0.40
Net loss		$ 4,228,000	$ 13,905,000	$ 7,448,000	$ 26,032,000	$ 2,961,000	$ 1,289,000	$ (673,000)	$ 4,069,000	$ 6,192,000	$ 6,382,000		$ 260,000	$ 37,731,000	$ 15,970,000	$ 4,488,000
Series A Preferred Unit in-kind distribution and fair value adjustment			0				33,000							(4,596,000)	(1,670,000)	0
Distribution Made to Member or Limited Partner, Distribution Paid In-kind, Fair Value Disclosure															0
Net loss attributable to partners			$ (10,827,000)				$ (1,790,000)							(36,659,000)	(17,640,000)	(4,228,000)
Interest in net loss														$ 0	$ 0	$ (22,910,000)
Basic and diluted net loss per common unit (in dollars per share) | $ / shares		$ (0.71)												$ (0.93)		$ (0.17)
Unvested common units excluded in computation of diluted per-unit amounts (in shares) | shares			2,081				140,100
Limited Partners [Member]
Earnings Per Unit of the Partnership
Unvested common units excluded in computation of diluted per-unit amounts (in shares) | shares													143,220
Class B Convertible Units [Member]
Earnings Per Unit of the Partnership
Conversion of Stock, Shares Converted | shares														0
Net loss			$ 3,119,000											$ 7,436,000
Series A Preferred Unit in-kind distribution and fair value adjustment			3,712,000											$ 9,610,000
Southcross Holdings Common [Member]
Earnings Per Unit of the Partnership
Conversion of Stock, Shares Converted | shares														252,687
Net loss attributable to partners			$ (3,154,000)										$ (6,409,000)	$ (6,409,000)
General Partner [Member]
Earnings Per Unit of the Partnership
Partners' Capital Account, Units | shares	29,925		1,044,170	1,038,852				534,638						1,038,852	534,638		5,075
Conversion of Stock, Shares Converted | shares														0
Net loss		$ 85,000	$ 217,000				$ 26,000							$ 626,000	$ 319,000
Series A Preferred Unit in-kind distribution and fair value adjustment															(1,670,000)
Distribution Made to Member or Limited Partner, Distribution Paid In-kind, Fair Value Disclosure			(76,000)				0							$ (207,000)	(33,000)
Common Limited Partners [Member]
Earnings Per Unit of the Partnership
Conversion of Stock, Shares Converted | shares														1,762,951
Net loss		2,072,000	4,902,000				757,000							$ 15,155,000	7,829,000
Distribution Made to Member or Limited Partner, Distribution Paid In-kind, Fair Value Disclosure															(17,000)
Net income (loss) allocated to limited partners			(4,936,000)				(1,045,000)							(20,175,000)	(8,683,000)	$ (2,072,000)
Interest in net loss		(8,683,000)	(4,936,000)				(1,045,000)							(20,175,000)		(2,072,000)
Dilutive interest in net loss		$ (8,683,000)	$ (4,936,000)				$ (1,045,000)							$ (20,175,000)		$ (2,072,000)
Weighted-average units - basic (in shares) | shares		12,224,997	23,800,943				18,285,220							21,641,635		12,213,713
Weighted-average units - diluted (in shares) | shares		12,224,997	23,800,943				18,285,220							21,641,635		12,213,713
Basic and diluted net loss per common unit (in dollars per share) | $ / shares			$ (0.21)				$ (0.06)
Unvested common units excluded in computation of diluted per-unit amounts (in shares) | shares							184,417							10,092
Subordinated Units
Earnings Per Unit of the Partnership
Net loss		$ 2,071,000	$ 2,513,000				$ 506,000							$ 8,105,000	7,822,000
Distribution Made to Member or Limited Partner, Distribution Paid In-kind, Fair Value Disclosure															(16,000)
Net income (loss) allocated to limited partners			(2,533,000)				(719,000)							(8,355,000)	(8,638,000)	$ (2,071,000)
Interest in net loss			(2,533,000)				(719,000)
Dilutive interest in net loss			$ (2,533,000)				$ (719,000)
Interest in net loss		(8,638,000)												(8,355,000)		(2,071,000)
Dilutive interest in net loss		$ (8,638,000)												$ (8,355,000)		$ (2,071,000)
Weighted-average units - basic (in shares) | shares		12,213,713	12,213,713				12,213,713							12,213,713		12,213,713
Weighted-average units - diluted (in shares) | shares		12,213,713	12,213,713				12,213,713							12,213,713		12,213,713
Basic and diluted net loss per common unit (in dollars per share) | $ / shares			$ (0.21)				$ (0.06)
Basic and diluted net loss per subordinated unit (in dollars per share) | $ / shares		$ (0.71)												$ (0.68)		$ (0.17)
Subordinated Units [Member]
Earnings Per Unit of the Partnership
Basic and diluted net loss per common unit (in dollars per share) | $ / shares								$ (0.01)	$ (0.19)	$ (0.27)	$ (0.26)
Series A Convertible Preferred Units [Member]
Earnings Per Unit of the Partnership
Number of Quarters for which Quarterly Distributions in Kind Required to be Paid | item			4											4
Distribution Made to Member or Limited Partner Minimum Quarterly Distributions Declared Per Unit | $ / shares			$ 0.40
Conversion of Stock, Shares Converted | shares			2,015,638		2,015,638
Series A Preferred Unit in-kind distribution and fair value adjustment			$ 0				$ 33,000							$ (4,596,000)	(37,000)
Dividends, Preferred Stock, Paid-in-kind			0				(534,000)							$ (534,000)	$ (1,633,000)
Preferred Unit Conversion Common Units Collective Value as Percentage of Preferred Units that will be Convertible on Satisfaction of Specified Condition	110.00%
Series A Convertible Preferred Units [Member]
Earnings Per Unit of the Partnership
Unvested common units excluded in computation of diluted per-unit amounts (in shares) | shares														1,213,257
Senior Secured Credit Facility [Member] | Series A Convertible Preferred Units [Member]
Earnings Per Unit of the Partnership
Total capital infusion	$ 40,000,000
General Partner [Member] | General Partner [Member]
Earnings Per Unit of the Partnership
Net loss			$ 239,000				$ 26,000							$ 693,000
Cash Distribution [Member]
Earnings Per Unit of the Partnership
Distribution Made to Member or Limited Partner Minimum Quarterly Distributions Declared Per Unit | $ / shares			$ 0.4	$ 0.4	$ 0.4	$ 0.4	$ 0.4	$ 0.4	$ 0.40	$ 0.4	$ 0.4	$ 0.24		$ 0.40
Distribution paid in cash			$ 9,938,000	$ 13,368,000	$ 9,933,000	$ 14,575,000	$ 13,762,000	$ 13,755,000		$ 9,986,000	$ 9,973,000	$ 5,982,000		$ 9,987,000
Cash Distribution [Member] | General Partner [Member]
Earnings Per Unit of the Partnership
Distribution paid in cash			$ 418,000	416,000	413,000	290,000	$ 290,000	289,000		210,000	199,000	120,000		214,000
Cash Distribution [Member] | Subordinated Units | Limited Partners [Member]
Earnings Per Unit of the Partnership
Distribution Made to Member or Limited Partner Minimum Quarterly Distributions Declared Per Unit | $ / shares			$ 0.40				$ 0.40
Distribution paid in cash			$ 0	3,432,000	0	4,886,000	$ 4,886,000	4,885,000		4,886,000	4,886,000	2,931,000		$ 4,885,000
Cash Distribution [Member] | Common Limited Partners [Member] | Limited Partners [Member]
Earnings Per Unit of the Partnership
Distribution Made to Member or Limited Partner Minimum Quarterly Distributions Declared Per Unit | $ / shares														$ 1.60	$ 1.60	$ 0.24
Distribution paid in cash			$ 9,520,000	9,520,000	$ 9,520,000	$ 9,399,000	$ 8,586,000	$ 8,581,000		$ 4,890,000	$ 4,888,000	$ 2,931,000		$ 4,888,000
Cash Distribution [Member] | Subordinated Units [Member]
Earnings Per Unit of the Partnership
Distribution paid in cash				$ 0.28

EARNINGS PER LIMITED PARTNER 53

EARNINGS PER LIMITED PARTNER UNIT AND DISTRIBUTIONS (Details 2) - USD ($)	Aug. 04, 2014	Nov. 14, 2013	May. 15, 2013	Apr. 12, 2013	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2014	Nov. 06, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 05, 2015
Distributions
Minimum quarterly distribution (in dollars per unit)						$ 0.40
Ownership interest held by general partners (as a percent)						2.00%
In-kind unit distribution, fair value																			$ 0
Unvested common units excluded in computation of diluted per-unit amounts (in shares)						2,081				140,100
Aggregate distributions to unitholders						$ 13,368,000				$ 13,755,000								$ 52,645,000	$ 35,928,000
Phantom Units
Distributions
Aggregate distributions to unitholders		$ 63,800
Class B Convertible Units [Member]
Distributions
Minimum quarterly distribution (in dollars per unit)						$ 0.3257		$ 0.3257								$ 0.44
Minimum annual distribution (in dollars per unit)						$ 1.60												$ 1.60
Aggregate distributions to unitholders						$ 0.44
Class B Convertible Units [Member] | Subsequent Event [Member]
Distributions
Minimum quarterly distribution (in dollars per unit)					$ 0.3257
General Partner [Member]
Distributions
Ownership interest held by general partners (as a percent)	2.00%					2.00%												2.00%
Partners' Capital Account, Units			5,075	29,925		1,044,170	1,038,852				534,638							1,038,852	534,638
In-kind unit distribution, fair value						$ 76,000				0								$ 207,000	$ 33,000
Aggregate distributions to unitholders						416,000				$ 289,000								$ 1,282,000	$ 742,000
Conversion of Stock, Shares Converted																		0
General Partner [Member] | Class B Convertible Units [Member]
Distributions
Conversion of Stock, Shares Issued																		0
Subordinated Units [Member]
Distributions
Shares, Outstanding																					12,213,713
Conversion of Stock, Shares Converted																		0
Subordinated Units [Member] | Class B Convertible Units [Member]
Distributions
Conversion of Stock, Shares Issued																		0
Class B Convertible Units [Member]
Distributions
Aggregate distributions to unitholders						$ 0
Conversion of Stock, Shares Converted																		0
Class B Convertible Units [Member] | Class B Convertible Units [Member]
Distributions
Conversion of Stock, Shares Issued	14,633,000					15,149,636												14,633,000
Limited Partners [Member]
Distributions
Unvested common units excluded in computation of diluted per-unit amounts (in shares)																	143,220
Cash Distribution [Member]
Distributions
Distribution Made to Member or Limited Partner Unit Distributions Per Unit						$ 0.3257	$ 0.3257	0.3257
Minimum quarterly distribution (in dollars per unit)						$ 0.4	$ 0.4	$ 0.4	$ 0.4	$ 0.4	$ 0.4	$ 0.40	$ 0.4	$ 0.4	$ 0.24			$ 0.40
Minimum annual distribution (in dollars per unit)																		$ 1.60
Distribution paid in cash						$ 9,938,000	$ 13,368,000	$ 9,933,000	$ 14,575,000	$ 13,762,000	$ 13,755,000		$ 9,986,000	$ 9,973,000	$ 5,982,000			$ 9,987,000
Cash Distribution [Member] | General Partner [Member]
Distributions
Distribution paid in cash						418,000	416,000	413,000	290,000	290,000	289,000		210,000	199,000	120,000			$ 214,000
Cash Distribution [Member] | Limited Partners [Member] | Common Units
Distributions
Minimum quarterly distribution (in dollars per unit)																		$ 1.60	$ 1.60	$ 0.24
Distribution paid in cash						$ 9,520,000	$ 9,520,000	9,520,000	$ 9,399,000	$ 8,586,000	$ 8,581,000		$ 4,890,000	$ 4,888,000	$ 2,931,000			$ 4,888,000
In-kind [Member]
Distributions
Minimum annual distribution (in dollars per unit)																		$ 1.60
Maximum [Member] | Cash Distribution [Member]
Distributions
Distribution period						45 days	45 years											45 days
Maximum [Member] | Cash Distribution [Member] | General Partner [Member]
Distributions
Incentive distribution rights as a percentage of distribution from operating surplus in excess of stated per unit amount (as a percent)																		50.00%
Amount used to calculate additional distribution percentage (in dollars per share)																		$ 0.46
Class B Convertible Units [Member] | In-kind [Member]
Distributions
In-kind unit distribution						$ 265,118,000	$ 260,558,000	256,078,000
In-kind unit distribution, fair value						3,712,000	4,143,000	5,467,000
Class B Convertible Units [Member] | In-kind [Member] | General Partner [Member]
Distributions
In-kind unit distribution						5,410,000	5,318,000	5,226,000
In-kind unit distribution, fair value						$ 76,000	$ 85,000	$ 112,000
Series A Convertible Preferred Units [Member]
Distributions
Minimum quarterly distribution (in dollars per unit)						$ 0.40
Issuance of general partner units			$ 248,675	$ 1,466,325
Preferred units agreed to be sold													1,500,000
Series A convertible preferred units issued				1,715,000
Conversion of Stock, Shares Converted						2,015,638		2,015,638
Preferred Unit Conversion Common Units Collective Value as Percentage of Preferred Units that will be Convertible on Satisfaction of Specified Condition				110.00%
Series A Convertible Preferred Units [Member] | Senior Secured Credit Facility [Member]
Distributions
Total capital infusion				$ 40,000,000
Series A Convertible Preferred Units [Member] | Common Units [Member]
Distributions
Series A convertible preferred units issued				1,715,000
Series A Convertible Preferred Units [Member] | In-kind [Member]
Distributions
Distribution Made to Member or Limited Partner Unit Distributions Per Unit						$ 0.40
Minimum quarterly distribution (in dollars per unit)										$ 0.40	$ 0.40	$ 0.40	$ 0.35	$ 0.20
Annual distribution rate (percent)						7.00%												7.00%
In-kind unit distribution						$ 31,513,000				$ 31,513	$ 30,971	$ 30,439	$ 22,276	$ 2,199
In-kind unit distribution, fair value						534,000				534,000	558,000	511,000	512,000	51,000
Series A Convertible Preferred Units [Member] | In-kind [Member] | General Partner [Member]
Distributions
In-kind unit distribution						643,000				643	632	621	454	45
In-kind unit distribution, fair value						$ 11,000				$ 11,000	$ 11,000	$ 10,000	$ 10,000	$ 1,000

FINANCIAL INSTRUMENTS (Details)

FINANCIAL INSTRUMENTS (Details)	1 Months Ended	3 Months Ended		9 Months Ended	12 Months Ended
	Feb. 28, 2014USD ($)	Mar. 31, 2015USD ($)	Mar. 31, 2014USD ($)	Sep. 30, 2014USD ($)	Dec. 31, 2014USD ($)MMBTU	Dec. 31, 2013USD ($)MMBTUitem	Dec. 31, 2012USD ($)	Jun. 30, 2014USD ($)
Fair value of financial instruments
Derivative, Cap Interest Rate					1.50%
Derivative, notional value		$ 50,000,000			$ 20,000,000			$ 140,000,000
Repayments of Lines of Credit	$ 148,500,000
Derivative liability, non-current		(37,000)			(39,000)	$ 0
Interest Rate Derivatives, at Fair Value, Net		(216,000)			(160,000)	(263,000)
Derivative Asset		10,000			27,000	0
Unrealized Gain (Loss) on Derivatives		(167,000)	$ 32,000		(168,000)	$ 120,000	$ (141,000)
Number of outstanding month-ahead swap contracts | item						0
Derivative Liability		(239)			(214)
Interest Rate Swap 0.327% [Member]
Fair value of financial instruments
Derivative, fixed interest rate								0.327%
Derivative Liability, Fair Value, Gross Asset		(51)			(97)
Interest rate swap liability
Fair value of financial instruments
Derivative, notional value					$ 150,000,000
Derivative, fixed interest rate					0.54%
Interest rate cap
Fair value of financial instruments
Gain (Loss) on Sale of Derivatives		56,000	12,000		$ 316,000	$ 108,000	82,000
Unrealized Gain (Loss) on Derivatives		104,000	27,000		160,000	0	141,000
Commodity Swaps [Member]
Fair value of financial instruments
Gain (Loss) on Sale of Derivatives		125,000	(1,169,000)		$ 347,000	(659,000)	(12,000)
Derivative, Fair Value, Net						120,000
Derivative Asset, Fair Value, Gross Asset						140,000
Derivative Liability, Amount Offset Against Derivative Asset						20,000
Derivative Liability, Fair Value, Gross Liability						$ 20,000
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU					12,000	12,000
Unrealized Gain (Loss) on Derivatives		$ (111,000)	44,000		$ (8,000)	$ 120,000	0
Volume of month-ahead swap contracts (in MMBtu) | MMBTU						33,722
Interest Rate Swap 1.198% [Member]
Fair value of financial instruments
Derivative, notional value					50,000,000
Derivative, fixed interest rate		1.1975%		1.1975%
Derivative Liability, Fair Value, Gross Asset		$ (94)			(59)
Interest Rate Swap 1.196% [Member]
Fair value of financial instruments
Derivative, fixed interest rate		1.196%		1.196%
Derivative Liability, Fair Value, Gross Asset		$ (94)			(58)
Recurring basis | Significant Other Observable Inputs (Level 2) | Interest rate swap liability
Fair value of financial instruments
Derivative Asset, Current		13,000			27,000	$ 0
Fair value measurement		(202,000)			(175,000)	(263,000)
Derivatives designated as hedging instruments | Interest rate swap liability
Fair value of financial instruments
Derivative, notional value		$ 150,000,000
Derivative, fixed interest rate		0.54%
Change in value recognized in other comprehensive loss - effective portion					(11,000)	(148,000)	(745,000)
Hedging losses related to interest rate swap contract		$ (100,000)		$ (100,000)
Derivatives designated as hedging instruments | Interest rate cap
Fair value of financial instruments
Change in value recognized in other comprehensive loss - effective portion		0	(11,000)
Loss reclassified from accumulated other comprehensive loss to interest expense		0	$ 115,000		$ 221,000	$ 415,000	$ 268,000
LIBOR | Interest rate swap liability
Fair value of financial instruments
Derivative, term for variable interest rate					1 month
Other Current Assets [Member] | Commodity Swaps [Member]
Fair value of financial instruments
Derivative, Fair Value, Net		0			$ 112,000
Derivative Asset, Fair Value, Gross Asset		0			112,000
Derivative Liability, Fair Value, Gross Liability					0
Other Current Liabilities [Member] | Commodity Swaps [Member]
Fair value of financial instruments
Derivative, Fair Value, Net		0			0
Derivative Liability, Amount Offset Against Derivative Asset		0			0
Derivative Liability, Fair Value, Gross Liability		$ 0			$ 0

FINANCIAL INSTRUMENTS (Details

FINANCIAL INSTRUMENTS (Details 2)	3 Months Ended		12 Months Ended
	Mar. 31, 2015USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)MMBTUitem	Dec. 31, 2012USD ($)	Sep. 30, 2014	Jun. 30, 2014USD ($)
Derivatives
Derivative, notional value	$ 50,000,000		$ 20,000,000				$ 140,000,000
Derivative, Cap Interest Rate			1.50%
Number of outstanding month-ahead swap contracts | item				0
Unrealized loss on interest rate cap	(167,000)	$ 32,000	$ (168,000)	$ 120,000	$ (141,000)
Derivative Liability	(239)		(214)
Interest Rate Swap 0.327% [Member]
Derivatives
Derivative, fixed interest rate							0.327%
Derivative Liability, Fair Value, Gross Asset	(51)		(97)
Interest rate cap contract
Derivatives
Realized gain /(loss) on derivatives	56,000	12,000	316,000	108,000	82,000
Unrealized loss on interest rate cap	104,000	27,000	160,000	0	141,000
Interest rate cap contract | Derivatives designated as hedging instruments
Derivatives
Change in value recognized in other comprehensive loss - effective portion	0	(11,000)
Loss reclassified from accumulated other comprehensive loss to interest expense	0	115,000	221,000	415,000	268,000
Interest rate swap contract
Derivatives
Derivative, notional value			$ 150,000,000
Derivative, fixed interest rate			0.54%
Interest rate swap contract | Derivatives designated as hedging instruments
Derivatives
Derivative, notional value	$ 150,000,000
Change in value recognized in other comprehensive loss - effective portion			$ (11,000)	$ (148,000)	(745,000)
Derivative, fixed interest rate	0.54%
Commodity Swaps
Derivatives
Volume of month-ahead swap contracts (in MMBtu) | MMBTU				33,722
Derivative Asset, Fair Value, Gross Asset				$ 140,000
Derivative Liability, Fair Value, Gross Liability				(20,000)
Derivative Liability, Amount Offset Against Derivative Asset				20,000
Commodity swaps, net				120,000
Realized gain /(loss) on derivatives	$ 125,000	(1,169,000)	347,000	(659,000)	(12,000)
Unrealized loss on interest rate cap	$ (111,000)	$ 44,000	(8,000)	$ 120,000	$ 0
Interest Rate Swap 1.198% [Member]
Derivatives
Derivative, notional value			50,000,000
Derivative, fixed interest rate	1.1975%					1.1975%
Derivative Liability, Fair Value, Gross Asset	$ (94)		(59)
Interest Rate Swap 1.196% [Member]
Derivatives
Derivative, fixed interest rate	1.196%					1.196%
Derivative Liability, Fair Value, Gross Asset	$ (94)		(58)
Other Current Assets [Member] | Commodity Swaps
Derivatives
Derivative Asset, Fair Value, Gross Asset	0		112,000
Derivative Liability, Fair Value, Gross Liability			0
Commodity swaps, net	0		112,000
Other Current Liabilities [Member] | Commodity Swaps
Derivatives
Derivative Liability, Fair Value, Gross Liability	0		0
Derivative Liability, Amount Offset Against Derivative Asset	0		0
Commodity swaps, net	$ 0		$ 0

LONG-LIVED ASSETS (Details)

LONG-LIVED ASSETS (Details) - USD ($)	Jan. 20, 2015	Jan. 31, 2013	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2014
Property, plant and equipment
Total property, plant and equipment			$ 1,144,564,000		$ 1,109,398,000	$ 644,356,000
Accumulated depreciation and amortization			(159,252,000)		(142,234,000)	(79,908,000)
Property, plant and equipment, net			1,060,633,000		1,058,570,000	575,795,000
Depreciation expense			17,031,000	$ 8,528,000	46,050,000	33,548,000	$ 18,977,000
Capitalized interest included in property, plant and equipment, net			302,000	$ 99,000	3,087,000	1,457,000	$ 6,268,000
Capital leases			1,100		1,033	908
Property, plant and equipment, service charges					5,500,000
Insurance recoveries					3,900,000	1,000,000
Insurance claims deductible amount	$ 500,000	$ 300,000
Estimated Insurance Recoveries								$ 600,000
Intangible assets, net			$ 1,497,000		$ 1,511,000	1,568,000
Expected useful lives of contracts			30 years		30 years
Property, plant and equipment excluding construction in progress and land and other
Property, plant and equipment
Property, plant and equipment, net			$ 985,312,000		$ 967,164,000	564,448,000
Pipelines
Property, plant and equipment
Total property, plant and equipment			503,888,000		$ 488,592,000	344,721,000
Pipelines | Minimum [Member]
Property, plant and equipment
Estimated Useful life					15 years
Pipelines | Maximum [Member]
Property, plant and equipment
Estimated Useful life					30 years
Gas processing, treating and other plants
Property, plant and equipment
Estimated Useful life					15 years
Total property, plant and equipment			532,538,000		$ 515,080,000	254,133,000
Compressors
Property, plant and equipment
Total property, plant and equipment			64,856,000		$ 62,741,000	20,030,000
Compressors | Minimum [Member]
Property, plant and equipment
Estimated Useful life					7 years
Compressors | Maximum [Member]
Property, plant and equipment
Estimated Useful life					15 years
Rights of way and easements
Property, plant and equipment
Estimated Useful life					15 years
Total property, plant and equipment			37,263,000		$ 37,238,000	20,729,000
Furniture, fixtures & equipment
Property, plant and equipment
Estimated Useful life					5 years
Total property, plant and equipment			3,735,000		$ 3,671,000	3,347,000
Capital lease vehicles
Property, plant and equipment
Total property, plant and equipment			2,284,000		$ 2,076,000	1,396,000
Capital lease vehicles | Minimum [Member]
Property, plant and equipment
Estimated Useful life					3 years
Capital lease vehicles | Maximum [Member]
Property, plant and equipment
Estimated Useful life					5 years
Construction in progress
Property, plant and equipment
Property, plant and equipment, net			51,319,000		$ 63,858,000	6,039,000
Land and other
Property, plant and equipment
Property, plant and equipment, net			$ 24,002,000		$ 27,548,000	$ 5,308,000

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details)	Aug. 04, 2014USD ($)	Nov. 30, 2012	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015USD ($)	Sep. 30, 2014	Mar. 31, 2014USD ($)	Jun. 30, 2013shares	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2012USD ($)	Mar. 13, 2014USD ($)	Apr. 12, 2013USD ($)shares	Mar. 27, 2013USD ($)	Mar. 25, 2013USD ($)	Nov. 07, 2012USD ($)
LONG TERM DEBT
Long-term Debt					$ 505,092,000				$ 471,129,000	$ 267,300,000
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months									4,500,000
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Two and Three									4,500,000
Long-term Debt, Maturities, Repayments of Principal in Year Three									4,500,000
Long-term Debt, Maturities, Repayments of Principal in Year Four									4,500,000
Long-term Debt, Maturities, Repayments of Principal in Year Five									34,500,000
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Four and Five									$ 423,129,000
Debt Instrument, Term		5 years							5 years
Other Long-term Debt, Current					(4,500,000)				$ (4,500,000)	0
Other Long-term Debt					444,592,000				445,629,000	0
Long-term Debt, Gross					509,592,000				475,629,000	267,300,000
Total long-term debt									471,129,000	267,300,000
Average borrowings outstanding					512,093,000		$ 192,403,000		308,670,000	243,920,000
Maximum outstanding borrowings					522,750,000		$ 267,300,000		491,875,000	267,300,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net					88,800,000
Loss on extinguishment of debt									2,316,000	0	$ 1,764,000
Proceeds from Issuance of Other Long-term Debt	$ 450,000,000								450,000,000	0	$ 0
Line of Credit Facility, Interest Rate Description	0.01
Amortization of Debt Discount (Premium)	$ 0.01
Debt Instrument, Periodic Payment	$ 1,125,000
General Partner [Member]
LONG TERM DEBT
Long-term Line of Credit					20,830,000				30,130,000	31,260,000
Credit Facility, due November 2017 [Member]
LONG TERM DEBT
Long-term Debt					65,000,000				30,000,000	267,300,000
Line of Credit Facility, Remaining Borrowing Capacity					$ 114,170,000				139,870,000	$ 69,000
Basis spread on variable rate (as a percent)	4.25%
Maximum borrowing capacity									$ 350,000,000			$ 350,000,000		$ 250,000,000	$ 350,000,000
Leverage ratio	4.50					5.75
Debt Instrument, Covenant Maximum Adjusted Consolidated Total Leverage Ratio					5.50
Credit Facility, due November 2017 [Member] | Credit Agreement Covenant September 30 2013 [Member]
LONG TERM DEBT
Debt Instrument, Interest Rate During Period					5.10%		4.60%		4.60%	4.40%
Credit Facility, due November 2017 [Member] | Subsequent Event [Member]
LONG TERM DEBT
Debt Instrument, Covenant Maximum Adjusted Consolidated Total Leverage Ratio				5.5
Letter of Credit [Member]
LONG TERM DEBT
Maximum borrowing capacity	$ 75,000,000												$ 75,000,000			$ 200,000,000
Secured Debt [Member] | Subsequent Event [Member]
LONG TERM DEBT
Debt Instrument, Covenant Maximum Adjusted Consolidated Total Leverage Ratio			5	5.25
Secured Debt [Member] | Scenario, Forecast [Member]
LONG TERM DEBT
Debt Instrument, Covenant Maximum Adjusted Consolidated Total Leverage Ratio			5	5.25
Series A Convertible Preferred Units [Member]
LONG TERM DEBT
Units issued and sold | shares													1,715,000
Preferred units agreed to be sold | shares								1,500,000
Common Units [Member] | Series A Convertible Preferred Units [Member]
LONG TERM DEBT
Units issued and sold | shares													1,715,000
Pipelines [Member]
LONG TERM DEBT
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	$ 100,000,000

COMMITMENTS AND CONTINGENT LI58

COMMITMENTS AND CONTINGENT LIABILITIES (Details) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2015USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2014USD ($)item	Dec. 31, 2013USD ($)	Dec. 31, 2012USD ($)
Legal Matters
Number of pending proceedings | item			0
Amortization expense related to capital leases	$ 100		$ 600	$ 500
Future minimum annual rental commitments under capital leases
2,014			468
2,015			283
2,016			212
2,017			95
2,018			3
Total future payments			1,026
Less: Imputed interest			1,061
Operating Leases, Future Minimum Payments, Due Thereafter			11,358
Future lease payments			(35)
Capital lease obligation	207	$ 307	708	1,396
Future minimum annual rental commitments under our operating leases
2,014			1,170
2,015			1,156
2,016			1,122
2,017			1,055
2,018			1,080
Total			5,775
Expenses associated with operating leases
Expenses associated with operating leases	$ 1,200	$ 300	$ 1,500	$ 1,500	$ 2,200

COMMITMENTS AND CONTINGENT LI59

COMMITMENTS AND CONTINGENT LIABILITIES (Details 2) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Purchase commitments
Capital Lease Obligations, Current	$ 451		$ 455	$ 481
Capital Leases, Income Statement, Amortization Expense	100,000		600,000	500,000
Capital lease obligation	207,000	$ 307,000	708,000	1,396,000
Operating Leases, Rent Expense, Net	1,200,000	$ 300,000	1,500,000	1,500,000	$ 2,200,000
Capital Lease Obligations, Noncurrent	649		578	427
Capital Lease Obligations	1,100		1,033	$ 908
Capital Addition Purchase Commitments [Member]
Purchase commitments
Commitments	$ 18,300,000		17,900,000
Other planned capital projects
Purchase commitments
Commitments			$ 0

TRANSACTIONS WITH RELATED PAR60

TRANSACTIONS WITH RELATED PARTIES (Details) - USD ($)	Apr. 02, 2012	Mar. 31, 2015	Sep. 30, 2014	Mar. 31, 2014	Jun. 30, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Apr. 12, 2013	Aug. 06, 2009
Related Party Transaction [Line Items]
Transaction costs associated with acquisition						$ 9,900,000
Accounts Receivable, Related Parties		$ 8,882,000				11,325,000	$ 0
Compensation		100,000				900,000
Expenses incurred from transactions with related party		46,000		$ 0		380,000	463,000	$ 0
Related Party Transaction Reimbursement Expenses from Transactions with Related Party		7,915,000		7,418,000		27,037,000	22,628,000	0
Revenue from Related Parties		7,447,000		$ 0		13,267,000	0	0
Due to Affiliate, Current		(3,803,000)				(12,856,000)	0
Due from Affiliate, Current						11,300,000
Due to Affiliate		3,800,000				12,900,000
Severance Costs						600,000
Operating Costs and Expenses		1,700,000				1,700,000
Series A Convertible Preferred Units [Member]
Related Party Transaction [Line Items]
Units issued and sold									1,715,000
Cash purchase price (in dollars per unit)				$ 22.86					$ 22.86
Preferred units agreed to be sold					1,500,000
Common Units [Member] | Series A Convertible Preferred Units [Member]
Related Party Transaction [Line Items]
Units issued and sold									1,715,000
Charlesbank
Related Party Transaction [Line Items]
Related party transaction, management fees							500,000	600,000
Related party transaction, expenses							68,000
Related party transaction, amount paid to related party						0
Expenses incurred from transactions with related party		14,000		$ 0		340,000	463,000	0
Charlesbank | Southcross Energy Partners LLC [Member]
Related Party Transaction [Line Items]
Cash purchase price (in dollars per unit)										$ 1
Southcross Energy LLC [Member]
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties						500,000
EIG [Member]
Related Party Transaction [Line Items]
Expenses incurred from transactions with related party		16,000		0		20,000	0	0
General Partner [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party						1,000,000
Affiliates of Wells Fargo Bank
Related Party Transaction [Line Items]
Fees paid to related party		400,000		200,000		9,500,000	1,800,000	5,900,000
EIG [Member]
Related Party Transaction [Line Items]
Expenses incurred from transactions with related party						2,800,000
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party						100,000
Tailwater [Member]
Related Party Transaction [Line Items]
Expenses incurred from transactions with related party		16,000		0		20,000	0	0
T2 Gas Utilities [Domain]
Related Party Transaction [Line Items]
Due to Affiliate						4,600,000
General and Administrative Expense [Member]
Related Party Transaction [Line Items]
Related Party Transaction Reimbursement Expenses from Transactions with Related Party		3,134,000		3,475,000		10,944,000	9,364,000	0
Operating Expense [Member]
Related Party Transaction [Line Items]
Related Party Transaction Reimbursement Expenses from Transactions with Related Party		4,781,000		$ 3,943,000		16,093,000	$ 13,264,000	$ 0
T2 Gas Utilities [Domain]
Related Party Transaction [Line Items]
Due from Affiliate, Current						2,300,000
T2 Cogen [Member]
Related Party Transaction [Line Items]
Due from Affiliate, Current		600,000				2,800,000
Due to Affiliate		1,700,000
Southcross Holdings Common [Member]
Related Party Transaction [Line Items]
Due from Affiliate, Current		900,000				5,800,000
Due to Affiliate						5,400,000
T2 Eagle Ford [Member]
Related Party Transaction [Line Items]
Due from Affiliate, Current		1,300,000
Due to Affiliate		500,000
T2 LaSalle [Member]
Related Party Transaction [Line Items]
Due from Affiliate, Current		100,000
Due to Affiliate		100,000
TexStar Rich Gas System [Member]
Related Party Transaction [Line Items]
Due from Affiliate, Current		5,600,000
Due to Affiliate		$ 1,400,000
LTIP [Member]
Related Party Transaction [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost			$ 7,200,000
Equity Equivalent Units [Member]
Related Party Transaction [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost			$ 100,000			100,000
Southcross Energy LLC [Member] | Equity Equivalent Units [Member]
Related Party Transaction [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost						1,200,000
TexStar Rich Gas System [Member]
Related Party Transaction [Line Items]
Professional Fees						1,700,000
Onyx Midstream LP & Onyx Pipeline Company [Member]
Related Party Transaction [Line Items]
Professional Fees						$ 300,000
Equity Equivalent Units [Member] | Southcross Energy Partners LLC [Member]
Related Party Transaction [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted	15,000

SERIES A CONVERTIBLE PREFERRE61

SERIES A CONVERTIBLE PREFERRED UNITS SERIES A CONVERTIBLE PREFERRED UNITS (Details) $ / shares in Units, $ in Thousands	Apr. 12, 2013USD ($)itemvote$ / shares$ / unitshares	Feb. 28, 2014	Mar. 31, 2015USD ($)shares	Sep. 30, 2014shares	Mar. 31, 2014USD ($)$ / sharesshares	Jun. 30, 2013shares	Dec. 31, 2014USD ($)shares	Dec. 31, 2013USD ($)	Dec. 31, 2012USD ($)
Capital Unit [Line Items]
Additional capital contributions							$ 25,000
Series A Preferred Unit in-kind distribution and fair value adjustment			$ 0		$ (33)		4,596	$ 1,670	$ 0
Series A Convertible Preferred Units [Member]
Capital Unit [Line Items]
Share price | $ / shares	$ 22.86				$ 22.86
Preferred units agreed to be sold | shares					1,500,000	1,500,000
Units issued and sold | shares	1,715,000
Proceeds from issuance of units	$ 39,200
Series A Preferred Unit in-kind distribution and fair value adjustment			$ 0		$ (33)		$ 4,596	37
Voting rights per preferred unit | vote	1
Rate per outstanding unit per quarter for preferred units to be distributed as in-kind distributions (in dollars per unit) | $ / unit	0.40
Rate per year of the per unit purchase price for preferred units to be distributed as in-kind distributions (as a percent)	7.00%
Rate per unit per quarter used for determination of cash distributions (in dollars per unit) | $ / unit	0.40
Number of succeeding quarters relating to estimated quarterly distributions used for determination of conversion of preferred units | item	4
Collective value of common units as a percentage of preferred units to be convertible on satisfaction of specified condition	110.00%
Conversion of Stock, Shares Converted | shares			2,015,638	2,015,638
Senior Secured Credit Facility [Member] | Series A Convertible Preferred Units [Member]
Capital Unit [Line Items]
Total capital infusion	$ 40,000
General Partner [Member]
Capital Unit [Line Items]
Additional capital contributions	$ 800
Ownership interest held by limited partners (as a percent)	2.00%	2.00%
Series A Preferred Unit in-kind distribution and fair value adjustment								$ 1,670
Conversion of Stock, Shares Converted | shares							0
Common Units [Member] | Series A Convertible Preferred Units [Member]
Capital Unit [Line Items]
Units issued and sold | shares	1,715,000

PARTNERS' CAPITAL AND MEMBERS62

PARTNERS' CAPITAL AND MEMBERS' EQUITY (Details) $ / shares in Units, $ in Thousands	Jan. 20, 2015	Nov. 13, 2014USD ($)	Aug. 04, 2014shares	Apr. 12, 2013$ / shares$ / unitshares	Nov. 26, 2012USD ($)shares	Nov. 07, 2012USD ($)	Mar. 20, 2012USD ($)	Feb. 28, 2014USD ($)shares	Dec. 31, 2012USD ($)	Jun. 30, 2015$ / shares	Mar. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)$ / sharesshares	Sep. 30, 2014USD ($)$ / sharesshares	Jun. 30, 2014$ / shares	Mar. 31, 2014USD ($)$ / shares	Dec. 31, 2013$ / sharesshares	Sep. 30, 2013$ / shares	Jun. 30, 2013$ / shares	Mar. 31, 2013$ / shares	Dec. 31, 2012$ / shares	Sep. 30, 2014$ / shares	Dec. 31, 2014USD ($)$ / sharesshares	Dec. 31, 2012USD ($)shares	May. 07, 2015shares	Nov. 05, 2014shares	Nov. 29, 2013USD ($)	May. 15, 2013shares	Dec. 31, 2011$ / sharesshares	Nov. 26, 2011shares	Aug. 06, 2009item$ / shares
Limited Partners' Capital Account [Line Items]
Public offering, amount authorized | $																										$ 675,000
Partners' Capital Account, Public Sale of Units Net of Offering Costs | $		$ 75,000
Repurchase and retirement of Southcross Energy LLC common units | $									$ 187,764													$ 144,671
Proceeds from public offering, net of underwriters' discounts and structuring fees | $																							$ 187,764
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest											2.00%
Preferred Stock, Participation Rights											1											1
Distribution Made to Member or Limited Partner Minimum Quarterly Distributions Declared Per Unit | $ / shares											$ 0.40
Business Acquisition, Percentage of Voting Interests Acquired											80.00%
Net proceeds | $											$ 0				$ 144,715
Capital contribution | $									262,826		$ 0				$ (3,115)							$ 11,316
Ownership Interest Percentage of Parent in Consolidated Subsidiaries											57.40%	100.00%	57.40%								57.40%	100.00%
Vesting period	1 year
Amount of incentive units repurchased and retired | $									25,205
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number											84,423
Series A Convertible Preferred Units [Member]
Limited Partners' Capital Account [Line Items]
Preferred Unit Conversion Common Units Collective Value as Percentage of Preferred Units that will be Convertible on Satisfaction of Specified Condition				110.00%
Distribution Made to Member or Limited Partner Minimum Quarterly Distributions Declared Per Unit | $ / shares											$ 0.40
Cash purchase price (in dollars per unit) | $ / shares				$ 22.86											$ 22.86
Series A convertible preferred units issued				1,715,000
Rate per outstanding unit per quarter for preferred units to be distributed as in-kind distributions (in dollars per unit) | $ / unit				0.40
Rate per unit per quarter used for determination of cash distributions (in dollars per unit) | $ / unit				0.40
Conversion of Stock, Shares Converted											(2,015,638)		(2,015,638)
Subordinated Units [Member]
Limited Partners' Capital Account [Line Items]
Preferred Stock, Shares Outstanding											12,213,713	12,213,713				12,213,713						12,213,713
Units authorized for public offering																						0
Conversion of Stock, Shares Converted																						0
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number																						0
Distribution Made to Limited Partner, Unit Distribution											0											0
Series A Preferred Stock [Member]
Limited Partners' Capital Account [Line Items]
Preferred Stock, Shares Outstanding												0				1,769,915						0
Units authorized for public offering																						0
Conversion of Stock, Shares Converted																						(1,832,399)
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number																						0
Distribution Made to Limited Partner, Unit Distribution																						62,484
General Partner [Member]
Limited Partners' Capital Account [Line Items]
Units authorized for public offering																						187,755
Ownership interest held by limited partners (as a percent)				2.00%				2.00%
Repurchase and retirement of Southcross Energy LLC common units | $															$ 0
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest			2.00%								2.00%											2.00%
Capital contribution | $									6,713						3,115							$ 9,991
Partners' Capital Account, Units				29,925							1,044,170	1,038,852				534,638						1,038,852					5,075
Conversion of Stock, Shares Converted																						0
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number																						0
Distribution Made to Limited Partner, Unit Distribution											5,318											316,459
Subordinated Limited Partners [Member]
Limited Partners' Capital Account [Line Items]
Repurchase and retirement of Southcross Energy LLC common units | $															0
Capital contribution | $									164,464						0							$ 345
Limited Partners' Capital Account, Units Authorized																									12,213,713
Subordinated Limited Partners [Member] | Subsequent Event [Member]
Limited Partners' Capital Account [Line Items]
Limited Partners' Capital Account, Units Authorized																								12,213,713
Common Units
Limited Partners' Capital Account [Line Items]
Units authorized for public offering																						9,200,000
Repurchase and retirement of Southcross Energy LLC common units | $									187,764						144,715							$ 144,671
Capital contribution | $									43,274						0							$ 809
Common units outstanding											21,684,543	21,684,543				10,390,272						21,684,543
Amount of incentive units repurchased and retired | $									25,205
Conversion of Stock, Shares Converted																						(1,762,951)
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number																						331,320
Distribution Made to Limited Partner, Unit Distribution											0											0
Class B Convertible Units [Member]
Limited Partners' Capital Account [Line Items]
Preferred Stock, Shares Outstanding											15,149,636	14,889,078				0						14,889,078
Units authorized for public offering																						0
Repurchase and retirement of Southcross Energy LLC common units | $															$ 0
Capital contribution | $																						$ 171
Conversion of Stock, Shares Converted																						0
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number																						0
Distribution Made to Limited Partner, Unit Distribution											260,558											256,078
Southcross Holdings Common [Member]
Limited Partners' Capital Account [Line Items]
Units authorized for public offering																						0
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest			100.00%
Common units outstanding											2,116,400	2,116,400				0						2,116,400
Partners' Capital Account, Units, Acquisitions																						1,863,713
Conversion of Stock, Shares Converted																						(252,687)
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number																						0
Distribution Made to Limited Partner, Unit Distribution											0											0
Common Units [Member]
Limited Partners' Capital Account [Line Items]
Common units outstanding																									2,116,400
Common Units [Member] | Series A Convertible Preferred Units [Member]
Limited Partners' Capital Account [Line Items]
Series A convertible preferred units issued				1,715,000
Redeemable
Limited Partners' Capital Account [Line Items]
Series A convertible preferred units issued												14,889,078				1,769,915						14,889,078						1,415,729
Common units [Member]
Limited Partners' Capital Account [Line Items]
Units authorized for public offering								9,200,000
Estimated cost of public offering | $								$ 400				$ 400										$ 400
Number of units issued																													1,350,000
Net proceeds | $					$ 25,200
Units reacquired from the Predecessor					1,350,000
Class B Convertible Units [Member]
Limited Partners' Capital Account [Line Items]
Distribution Made to Member or Limited Partner Minimum Quarterly Distributions Declared Per Unit | $ / shares											$ 0.3257		$ 0.3257								$ 0.44
Class B Convertible Units [Member] | Subsequent Event [Member]
Limited Partners' Capital Account [Line Items]
Distribution Made to Member or Limited Partner Minimum Quarterly Distributions Declared Per Unit | $ / shares										$ 0.3257
Class B Convertible Units [Member] | Subordinated Units [Member]
Limited Partners' Capital Account [Line Items]
Conversion of Stock, Shares Issued																						0
Class B Convertible Units [Member] | Series A Preferred Stock [Member]
Limited Partners' Capital Account [Line Items]
Conversion of Stock, Shares Issued																						0
Class B Convertible Units [Member] | General Partner [Member]
Limited Partners' Capital Account [Line Items]
Conversion of Stock, Shares Issued																						0
Class B Convertible Units [Member] | Common Units
Limited Partners' Capital Account [Line Items]
Conversion of Stock, Shares Issued																						0
Class B Convertible Units [Member] | Class B Convertible Units [Member]
Limited Partners' Capital Account [Line Items]
Conversion of Stock, Shares Issued			14,633,000								15,149,636											14,633,000
Class B Convertible Units [Member] | Southcross Holdings Common [Member]
Limited Partners' Capital Account [Line Items]
Conversion of Stock, Shares Issued																						0
Class A
Limited Partners' Capital Account [Line Items]
Amount of incentive units repurchased and retired | $									$ 15,300
Southcross Energy Partners LLC [Member]
Limited Partners' Capital Account [Line Items]
Number of members of the Predecessor's management team that purchased units | item																														5
Amount of incentive units repurchased and retired | $							$ 15,300
Southcross Energy Partners LLC [Member] | Charlesbank
Limited Partners' Capital Account [Line Items]
Cash purchase price (in dollars per unit) | $ / shares																														$ 1
Southcross Energy Partners LLC [Member] | Time-vesting units
Limited Partners' Capital Account [Line Items]
Vesting period																						5 years
Southcross Energy Partners LLC [Member] | General Partner [Member]
Limited Partners' Capital Account [Line Items]
Proceeds from public offering, net of underwriters' discounts and structuring fees | $						$ 168,000
Southcross Energy Partners LLC [Member] | Class A
Limited Partners' Capital Account [Line Items]
Common units unvested																							217,483
Southcross Energy Partners LLC [Member] | Class B
Limited Partners' Capital Account [Line Items]
Cash purchase price (in dollars per unit) | $ / shares																												$ 1
Series A convertible preferred units issued																												57,279
Common units unvested																							34,367
Cash Distribution [Member]
Limited Partners' Capital Account [Line Items]
Distribution Made to Member or Limited Partner Minimum Quarterly Distributions Declared Per Unit | $ / shares											$ 0.4	$ 0.4	$ 0.4	$ 0.4	$ 0.4	$ 0.4	$ 0.40	$ 0.4	$ 0.4	$ 0.24		$ 0.40
Cash Distribution [Member] | Maximum [Member]
Limited Partners' Capital Account [Line Items]
Distribution Made to Member or Limited Partner Distribution Period											45 days	45 years										45 days
TexStar Rich Gas System [Member]
Limited Partners' Capital Account [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired			100.00%
Equity Equivalent Units [Member]
Limited Partners' Capital Account [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost | $													$ 100									$ 100
Equity Equivalent Units [Member] | Southcross Energy LLC [Member]
Limited Partners' Capital Account [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost | $																						$ 1,200

SOUTHCROSS ENERGY LLC PREFERR63

SOUTHCROSS ENERGY LLC PREFERRED UNITS (Details) - Related Party [Domain] - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2012	Nov. 07, 2012
Southcross Energy LLC preferred units
Series A convertible preferred units outstanding	11,850,374
Preferred Stock, Par or Stated Value Per Share	$ 10
Preferred units | Southcross Energy Partners LLC [Member]
Southcross Energy LLC preferred units
Cumulative right to receive future cash distributions		$ 31.8	$ 43.3
Preferred units
Southcross Energy LLC preferred units
Preferred Unit Distribution Rights in Kind Distributions Rate of Preferred Units as Percentage Per Year of Per Unit Purchase Price	10.00%

INCENTIVE COMPENSATION (Details

INCENTIVE COMPENSATION (Details) - USD ($)	Jan. 20, 2015	Apr. 02, 2012	Dec. 31, 2012	Mar. 31, 2015	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2013
Unit based compensation
Vesting period	1 year
Weighted-average grant date fair value
Forfeited units (in dollars per unit)								$ 23.01
Unit-based compensation expense				$ 813,000			$ 529,000	$ 10,074,000	$ 2,186,000	$ 630,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested Options Forfeited, Number of Shares								(1,050)
Phantom Units
Units
Vested units (in shares)								(338,694)
Weighted-average grant date fair value
Vested units (in dollars per share)								$ 17.45
Phantom Units | Southcross Energy Partners LLC [Member]
Units
Vested units (in shares)			0						(40,272)
Weighted-average grant date fair value
Vested units (in dollars per share)			$ 0						$ 22.30
Phantom Units | Minimum [Member] | Southcross Energy Partners LLC [Member]
Weighted-average grant date fair value
Percentage of voting power that must change hands resulting in a change in control for the awards to vest									50.00%
Equity Equivalent Units [Member] | Southcross Energy Partners LLC [Member]
Unit based compensation
Vesting period								3 years
Weighted-average grant date fair value
Number of units grated		15,000
Unit-based compensation expense									$ 600,000	$ 400,000
Incentive Plan
Unit based compensation
Vesting period				3 years				3 years
Units
Unvested at the beginning of the period (in shares)			0	470,750			182,673	182,673	144,500
Granted units (in shares)			146,000	372,283				787,321	112,179
Forfeited units (in shares)			(1,500)	(17,514)					(20,700)
Units recaptured for tax withholdings (in shares)								(159,500)	(13,034)
Unvested at the end of the period (in shares)			144,500	825,519				470,750	182,673	144,500
Weighted-average grant date fair value
Unvested at the beginning of the period (in dollars per unit)			$ 0	$ 20.45			$ 22.55	$ 22.55	$ 23.01
Granted units (in dollars per unit)			23.01	13.80				19.82	21.96
Forfeited units (in dollars per unit)			23.01	20.69					22.09
Units recaptured for tax withholdings (in dollars per unit)								17.06	23.01
Unvested at the end of the period (in dollars per unit)			$ 23.01	$ 18.15				$ 20.45	$ 22.55	$ 23.01
Fair value				$ 5,100,000		$ 0		$ 15,600,000	$ 2,500,000
Unamortized compensation expense				$ 12,900,000				$ 9,100,000	$ 3,600,000		$ 3,200,000
Period of amortization of compensation expense				3 years				3 years
Units available for issuance (in shares)				545,515			1,525,121	900,284	1,527,055
Employee Savings Plan
Weighted-average grant date fair value
Employer matching contribution, percent of employees' contribution				100.00%				100.00%
Employer matching contribution, percent of employees' gross pay				6.00%				6.00%
Maximum annual contributions by employer, amount				$ 17,500				$ 17,500
Matching contributions expensed for employee savings plan				$ 181,000			$ 356,000	927,000	$ 628,000	$ 512,000
LTIP [Member]
Weighted-average grant date fair value
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost					$ 7,200,000
Equity Equivalent Units [Member]
Weighted-average grant date fair value
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost					$ 100,000			$ 100,000
Phantom Units
Weighted-average grant date fair value
Preferred Units, Authorized									10,832

REVENUES (Details)

REVENUES (Details) - USD ($) $ in Thousands	3 Months Ended									12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues [Abstract]
Sales of natural gas	$ 112,786				$ 145,358					$ 530,947	$ 405,206	$ 325,421
Sales of NGLs and condensate	37,183				51,874					226,218	169,523	124,139
Transportation, gathering and processing fees	35,053				16,115					90,807	59,392	46,113
Other	916				244					541	601	456
Revenues:	$ 185,938	$ 227,182	$ 212,676	$ 195,063	$ 213,591	$ 175,140	$ 160,629	$ 154,703	$ 144,250	$ 848,513	$ 634,722	$ 496,129

EQUITY IN JOINT VENTURES (Detai

EQUITY IN JOINT VENTURES (Details) $ in Thousands	2 Months Ended	3 Months Ended									10 Months Ended	12 Months Ended
	Dec. 31, 2012USD ($)	Mar. 31, 2015USD ($)joint_venture	Dec. 31, 2014USD ($)	Sep. 30, 2014USD ($)segment	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Sep. 30, 2013USD ($)	Jun. 30, 2013USD ($)	Mar. 31, 2013USD ($)	Nov. 06, 2012USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2012USD ($)	Aug. 04, 2014	Dec. 31, 2011USD ($)
Business Acquisition [Line Items]
Equity Method Investment Summarized Financial Information, Equity		$ 145,675	$ 147,098									$ 147,098
Income (Loss) from Equity Method Investments		(3,552)										(6,496)	$ 0	$ 0
Revenues:		$ 185,938	227,182	$ 212,676	$ 195,063	$ 213,591	$ 175,140	$ 160,629	$ 154,703	$ 144,250		848,513	634,722	496,129
number of joint ventures		3		3
Property, plant and equipment, net		$ 1,060,633	1,058,570				575,795					1,058,570	575,795
Assets		1,294,721	1,316,314				652,315					1,316,314	652,315
Liabilities		609,674	619,210				336,787					619,210	336,787
Members' Equity	$ 326,467													326,467		$ (10,165)
Liabilities and Equity		1,294,721	1,316,314				652,315					1,316,314	652,315
Net Income (Loss) Attributable to Parent	$ (4,228)	(13,905)	(7,448)	$ (26,032)	$ (2,961)	$ (1,289)	673	$ (4,069)	$ (6,192)	$ (6,382)	$ (260)	(37,731)	(15,970)	$ (4,488)
Assets, Current		70,641	91,946				$ 69,184					91,946	$ 69,184
T2 Eagle Ford [Member]
Business Acquisition [Line Items]
Property, plant and equipment, net			38,851,000									38,851,000
Assets			47,774,000									47,774,000
Liabilities			8,547,000									8,547,000
Members' Equity			39,227,000									39,227,000
Liabilities and Equity			47,774,000									47,774,000
Equity Method Investment, Ownership Percentage															50.00%
Assets, Current			8,923,000									8,923,000
T2 Cogen [Member]
Business Acquisition [Line Items]
Property, plant and equipment, net			216,863,000									216,863,000
Assets			221,036,000									221,036,000
Liabilities			3,915,000									3,915,000
Members' Equity			217,121,000									217,121,000
Liabilities and Equity			221,036,000									221,036,000
Equity Method Investment, Ownership Percentage															50.00%
Assets, Current			4,173,000									4,173,000
T2 LaSalle [Member]
Business Acquisition [Line Items]
Property, plant and equipment, net			77,189,000									77,189,000
Assets			78,093,000									78,093,000
Liabilities			904,000									904,000
Members' Equity			77,189,000									77,189,000
Liabilities and Equity			78,093,000									78,093,000
Equity Method Investment, Ownership Percentage															25.00%
Assets, Current			904,000									904,000
T2 Cogen [Member]
Business Acquisition [Line Items]
Equity Method Investment Summarized Financial Information, Equity		19,444	19,615									19,615
Income (Loss) from Equity Method Investments		(681)										(2,141)
Revenues:		1,662										2,517
Net Income (Loss) Attributable to Parent		(1,361)										(4,281)
T2 Eagle Ford [Member]
Business Acquisition [Line Items]
Equity Method Investment Summarized Financial Information, Equity		107,237	108,185									108,185
Income (Loss) from Equity Method Investments		(2,491)										(3,656)
Revenues:		921										3,537
Net Income (Loss) Attributable to Parent		(4,997)										(6,277)
T2 LaSalle [Member]
Business Acquisition [Line Items]
Equity Method Investment Summarized Financial Information, Equity		18,994	$ 19,298									19,298
Income (Loss) from Equity Method Investments		(380)										(699)
Revenues:		379										1,163
Net Income (Loss) Attributable to Parent		$ (1,520)										$ (1,876)

CONCENTRATION OF CREDIT RISK 67

CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE (Details) - Customer concentration - Consolidated revenue - customer	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Formosa
Consolidated revenue concentration
Concentration risk percentage					24.30%
Sherwin
Consolidated revenue concentration
Concentration risk percentage	10.90%	12.20%	13.60%	11.70%	11.00%
Top ten customers
Consolidated revenue concentration
Concentration risk percentage	60.10%	64.60%	63.40%	59.70%	65.50%
Number of top customers	10

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details)

Jan. 20, 2015USD ($)barrelMMcf / d

Apr. 12, 2013

Feb. 28, 2014shares

Jan. 31, 2013USD ($)

Jun. 30, 2015$ / shares

Mar. 31, 2015$ / shares

Dec. 31, 2014$ / shares

Sep. 30, 2014$ / shares

Jun. 30, 2014$ / shares

Mar. 31, 2014$ / shares

Dec. 31, 2013$ / shares

Sep. 30, 2013$ / shares

Jun. 30, 2013$ / shares

Mar. 31, 2013$ / shares

Dec. 31, 2012$ / shares

Sep. 30, 2014$ / shares

Dec. 31, 2014$ / sharesshares

Dec. 31, 2012USD ($)

Subsequent events

Minimum quarterly distribution (in dollars per unit)

$ 0.40

Production Capacity | MMcf / d

135

Production, Barrels of Oil Equivalents | barrel

4,800

Proceeds from issuance under public offering | $

$ 187,764,000

Insurance claims deductible amount | $

$ 500,000

$ 300,000

Vesting period

1 year

Class B Convertible Units [Member]

Subsequent events

Minimum quarterly distribution (in dollars per unit)

0.3257

$ 0.3257

$ 0.44

Common units [Member]

Subsequent events

Units authorized for public offering | shares

9,200,000

General Partner [Member]

Subsequent events

Ownership interest held by limited partners (as a percent)

2.00%

2.00%

Units authorized for public offering | shares

187,755

Cash Distribution [Member]

Subsequent events

Minimum quarterly distribution (in dollars per unit)

$ 0.4

$ 0.4

$ 0.4

$ 0.4

$ 0.4

$ 0.4

$ 0.40

$ 0.4

$ 0.4

$ 0.24

$ 0.40

In Kind Distribution [Member]

Subsequent events

Incentive Distribution, Distribution Per Unit

$ 0.40

Subsequent Event [Member] | Class B Convertible Units [Member]

Subsequent events

Minimum quarterly distribution (in dollars per unit)

$ 0.3257

Processing Unit One [Member]

Subsequent events

Production Capacity | MMcf / d

80

Processing Unit Two [Member]

Subsequent events

Production Capacity | MMcf / d

55

SUBSEQUENT EVENTS (Details 2)

SUBSEQUENT EVENTS (Details 2)

May. 07, 2015USD ($)

Apr. 23, 2015$ / shares

Aug. 04, 2014USD ($)

Apr. 12, 2013USD ($)

Feb. 28, 2014

Sep. 30, 2015

Jun. 30, 2015$ / shares

Mar. 31, 2015USD ($)$ / shares

Dec. 31, 2014USD ($)$ / shares

Sep. 30, 2014$ / shares

Jun. 30, 2014$ / shares

Mar. 31, 2014USD ($)$ / shares

Dec. 31, 2013$ / shares

Sep. 30, 2013$ / shares

Jun. 30, 2013$ / shares

Mar. 31, 2013$ / shares

Dec. 31, 2012$ / shares

Sep. 30, 2014USD ($)$ / shares

Dec. 31, 2014USD ($)$ / shares

Dec. 31, 2013USD ($)

Dec. 31, 2012USD ($)

Mar. 13, 2014USD ($)

Mar. 27, 2013USD ($)

Mar. 25, 2013USD ($)

Nov. 07, 2012USD ($)

Subsequent events

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net

$ 88,800,000

Ownership interest held by general partners (as a percent)

2.00%

Distribution Made to Member or Limited Partner Minimum Quarterly Distributions Declared Per Unit | $ / shares

$ 0.40

Payments to Acquire Businesses, Gross

$ 80,000,000

$ 80,000,000

Payments to Acquire Businesses, Net of Cash Acquired

$ 0

$ 38,636,000

$ 44,038,000

$ 0

$ 0

General Partner Units [Member]

Subsequent events

Ownership interest held by limited partners (as a percent)

2.00%

2.00%

Ownership interest held by general partners (as a percent)

2.00%

2.00%

2.00%

Cash

Subsequent events

Distribution Made to Member or Limited Partner Unit Distributions Per Unit | $ / shares

$ 0.3257

$ 0.3257

$ 0.3257

Distribution Made to Member or Limited Partner Minimum Quarterly Distributions Declared Per Unit | $ / shares

0.4

$ 0.4

0.4

$ 0.4

$ 0.4

$ 0.4

$ 0.40

$ 0.4

$ 0.4

$ 0.24

$ 0.40

Subsequent Event [Member]

Subsequent events

Payments to Acquire Businesses, Gross

$ 77,600,000

Payments to Acquire Businesses, Net of Cash Acquired

$ 15,000,000

Subsequent Event [Member] | Cash

Subsequent events

Distribution per common and subordinated unit (in dollars per unit) | $ / shares

$ 0.40

Series A convertible preferred units

Subsequent events

Preferred unit Conversion Common Units Exchange Ratio on Satisfaction of Specified Condition

110.00%

Distribution Made to Member or Limited Partner Minimum Quarterly Distributions Declared Per Unit | $ / shares

$ 0.40

Maximum [Member] | Cash

Subsequent events

Distribution Made to Member or Limited Partner Distribution Period

45 days

45 years

45 days

Class B Convertible Units [Member]

Subsequent events

Distribution Made to Member or Limited Partner Minimum Quarterly Distributions Declared Per Unit | $ / shares

$ 0.3257

$ 0.3257

$ 0.44

Class B Convertible Units [Member] | Subsequent Event [Member]

Subsequent events

Distribution Made to Member or Limited Partner Minimum Quarterly Distributions Declared Per Unit | $ / shares

$ 0.3257

Subordinated Limited Partners [Member] | Cash | Limited Partner [Member]

Subsequent events

Distribution Made to Member or Limited Partner Minimum Quarterly Distributions Declared Per Unit | $ / shares

$ 0.40

$ 0.40

Senior Secured Credit Facility [Member]

Subsequent events

Line of Credit Facility, Maximum Borrowing Capacity

$ 350,000,000

$ 350,000,000

$ 350,000,000

$ 250,000,000

$ 350,000,000

Leverage ratio

4.50

5.75

Debt Instrument, Covenant Maximum Adjusted Consolidated Total Leverage Ratio

5.50

Senior Secured Credit Facility [Member] | Subsequent Event [Member]

Subsequent events

Debt Instrument, Covenant Maximum Adjusted Consolidated Total Leverage Ratio

5.5

Letter of Credit [Member]

Subsequent events

Line of Credit Facility, Maximum Borrowing Capacity

$ 75,000,000

$ 75,000,000

$ 200,000,000

Secured Debt [Member] | Subsequent Event [Member]

Subsequent events

Debt Instrument, Covenant Maximum Adjusted Consolidated Total Leverage Ratio

5

5.25

Scenario, Forecast [Member] | Secured Debt [Member]

Subsequent events

Debt Instrument, Covenant Maximum Adjusted Consolidated Total Leverage Ratio

5

5.25

Pipelines

Subsequent events

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net

$ 100,000,000

Eurodollar [Member]

Subsequent events

Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum

2.00%

Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum

4.50%

Base Rate [Member]

Subsequent events

Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum

1.00%

Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum

3.50%

Minimum Commitment Fee [Member]

Subsequent events

Line of Credit Facility, Commitment Fee Percentage

0.375%

Maximum Commitment Fee [Member]

Subsequent events

Line of Credit Facility, Commitment Fee Percentage

0.50%

SUPPLEMENTAL CASH FLOW INFORM70

SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) number in Thousands, $ in Thousands	Aug. 04, 2014	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restructuring Cost and Reserve [Line Items]
Series A Convertible preferred unit in-kind distributions and fair value adjustments				$ 45,624
Class B Convertible unit issuance, net				0	$ 38,832	$ 0
Change in value recognized in other comprehensive income		$ 0	$ 11	11	148	745
Capital lease obligation		207	307	708	1,396
Accrued distribution equivalent rights on the LTIP units		342	76	167	279
Accounts payable related to capital expenditures		22,793	1,628	29,645	4,946	40,707
Cash received for tax refunds			23	205	95	315
Cash paid for interest		6,841	2,776	16,206	13,043	$ 10,552
Noncash Investing and Financing Transactions, Other				$ 1,151	$ 0
Noncash or Part Noncash Acquisition, Interest Acquired				32300.00%
Business Combination, Consideration Transferred	$ 98,625			$ 98,625
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net		88,800
Deferred Revenue, Revenue Recognized		700	200
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual		800	1,200
2,015				1,156
2,016				1,122
2,017				1,055
2,018				1,080
Operating Leases, Future Minimum Payments, Due Thereafter				11,358
Natural Gas Pipeline Contracts [Member]
Restructuring Cost and Reserve [Line Items]
2,015		4,200
2,016		5,600
2,017		5,600
2,018		2,200
Operating Leases, Future Minimum Payments, Due in Six Years		2,200
Operating Leases, Future Minimum Payments, Due Thereafter		15,300
TexStar Rich Gas System [Member]
Restructuring Cost and Reserve [Line Items]
Consideration paid in excess of purchase price for the TexStar Rich Gas System	98,625			98,625
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	$ 305,789
Series A Convertible Preferred Units [Member]
Restructuring Cost and Reserve [Line Items]
Series A Convertible preferred unit in-kind distributions and fair value adjustments				5,129
Class B Convertible Units [Member]
Restructuring Cost and Reserve [Line Items]
Class B Convertible unit issuance, net				324,413
Proceeds from Issuance of Preferred Stock and Preference Stock, In Kind Units		$ 3,712	$ 0	$ 9,610

SUPPLEMENTAL SELECTED QUARTER71

SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (Details) - USD ($) $ / shares in Units, $ in Thousands	2 Months Ended	3 Months Ended									10 Months Ended	12 Months Ended
	Dec. 31, 2012	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Nov. 06, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Condensed Financial Statements, Captions [Line Items]
Revenues:		$ 185,938	$ 227,182	$ 212,676	$ 195,063	$ 213,591	$ 175,140	$ 160,629	$ 154,703	$ 144,250		$ 848,513	$ 634,722	$ 496,129
Gross operating margin			41,841	32,115	26,237	27,188	28,174	25,213	21,296	18,863
Income (loss) from operations		(2,786)	1,872	(15,658)	(1,134)	1,692	4,510	(357)	(2,831)	(4,317)		(13,228)	(2,995)	3,289
Net loss	$ (4,228)	(13,905)	$ (7,448)	$ (26,032)	$ (2,961)	(1,289)	$ 673	$ (4,069)	$ (6,192)	$ (6,382)	$ (260)	(37,731)	(15,970)	(4,488)
Payments of distributions and distribution equivalent rights		13,368				$ 13,755						$ 52,645	35,992	$ 0
Basic net (loss) income per common unit (in dollars per share)			$ 0.05	$ (0.49)	$ (0.34)	$ (0.06)	$ (0.01)	$ 0.19	$ (0.65)	$ (0.26)
Diluted net (loss) income per common unit (in dollars per share)			$ 0.05	$ (0.49)	$ (0.11)	$ (0.06)	(0.01)	(0.14)	(0.65)	(0.26)
Basic and diluted net loss per subordinated unit (in dollars per share)	$ (0.71)											$ (0.93)		$ (0.17)
Subordinated Units [Member]
Condensed Financial Statements, Captions [Line Items]
Basic and diluted net loss per subordinated unit (in dollars per share)							$ (0.01)	$ (0.19)	$ (0.27)	$ (0.26)
General Partner [Member]
Condensed Financial Statements, Captions [Line Items]
Net loss	$ (85)	$ (217)				$ (26)						$ (626)	$ (319)

Uncategorized Items - sxe-20141

Label	Element	Value
Partners' Capital Account, Unit-based Compensation	us-gaap_PartnersCapitalAccountUnitBasedCompensation	$ 192
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	us-gaap_OtherComprehensiveIncomeLossDerivativesQualifyingAsHedgesNetOfTax	(477)
Limited Partners' Capital Account, Distribution Amount	us-gaap_LimitedPartnersCapitalAccountDistributionAmount	$ 46,030
Redeemable Preferred Units [Member] | Predecessor [Member]
Preferred Units Par Value Per Unit	sxe_PreferredUnitsParValuePerUnit	$ 10
Preferred Units Cumulative Right to Receive Future Cash Distributions	sxe_PreferredUnitsCumulativeRightToReceiveFutureCashDistributions	$ 3,900
Preferred Units Accrual Value Percentage	sxe_PreferredUnitsAccrualValuePercentage	18.00%
Redeemable Preferred Units [Member] | Charlesbank and Existing Investors [Member] | Predecessor [Member]
Preferred Units, Issued	us-gaap_PreferredUnitsIssued	1,500
Preferred Units, Contributed Capital	us-gaap_PreferredUnitsContributedCapital	$ 15,000
Series B Redeemable Preferred Units [Member] | Predecessor [Member]
Preferred Units, Outstanding	us-gaap_PreferredUnitsOutstanding	3,350
Partners' Capital Account, Units, Redeemed	us-gaap_PartnersCapitalAccountUnitsRedeemed	2,490
Preferred Units Par Value Per Unit	sxe_PreferredUnitsParValuePerUnit	$ 10
Preferred Units Cumulative Right to Receive Future Cash Distributions	sxe_PreferredUnitsCumulativeRightToReceiveFutureCashDistributions	$ 3,800
Preferred Units Cumulative Right to Receive Future Cash Distributions	sxe_PreferredUnitsCumulativeRightToReceiveFutureCashDistributions	$ 4,400
Preferred Units Accrual Value Percentage	sxe_PreferredUnitsAccrualValuePercentage	18.00%
Series B Redeemable Preferred Units [Member] | Affiliate of Wells Fargo Securities LLC [Member] | Predecessor [Member]
Preferred Units, Issued	us-gaap_PreferredUnitsIssued	1,000
Preferred Units, Contributed Capital	us-gaap_PreferredUnitsContributedCapital	$ 10,000
Series B Redeemable Preferred Units [Member] | Charlesbank and Certain Predecessor Investors [Member] | Predecessor [Member]
Preferred Units, Issued	us-gaap_PreferredUnitsIssued	2,530
Preferred Units, Issued	us-gaap_PreferredUnitsIssued	750
Preferred Units, Contributed Capital	us-gaap_PreferredUnitsContributedCapital	$ 25,300
Preferred Units, Contributed Capital	us-gaap_PreferredUnitsContributedCapital	$ 7,500
Series C Redeemable Preferred Units [Member] | Predecessor [Member]
Preferred Units, Outstanding	us-gaap_PreferredUnitsOutstanding	3,000
Series C Redeemable Preferred Units [Member] | Charlesbank Other Institutional Investors and Certain Predecessor Investors [Member] | Predecessor [Member]
Preferred Units, Issued	us-gaap_PreferredUnitsIssued	3,000
Preferred Units, Contributed Capital	us-gaap_PreferredUnitsContributedCapital	$ 30,000
Preferred Units Par Value Per Unit	sxe_PreferredUnitsParValuePerUnit	$ 10
Preferred Units Cumulative Right to Receive Future Cash Distributions	sxe_PreferredUnitsCumulativeRightToReceiveFutureCashDistributions	$ 1,400
Preferred Units Accrual Value Percentage	sxe_PreferredUnitsAccrualValuePercentage	18.00%
Common Limited Partners [Member]
Partners' Capital Account, Unit-based Compensation	us-gaap_PartnersCapitalAccountUnitBasedCompensation	$ 192
Limited Partners' Capital Account, Distribution Amount	us-gaap_LimitedPartnersCapitalAccountDistributionAmount	9,589
Subordinated Limited Partners [Member]
Limited Partners' Capital Account, Distribution Amount	us-gaap_LimitedPartnersCapitalAccountDistributionAmount	36,441
AOCI Attributable to Parent [Member]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	us-gaap_OtherComprehensiveIncomeLossDerivativesQualifyingAsHedgesNetOfTax	(477)
Retained Earnings [Member]
Net Income (Loss) Attributable to Parent	us-gaap_NetIncomeLoss	(260)
Partners' Capital Account, Contributions	us-gaap_PartnersCapitalAccountContributions	49,717
Common Class A [Member] | Common Stock [Member]
Stock Repurchased and Retired During Period, Value	us-gaap_StockRepurchasedAndRetiredDuringPeriodValue	131
Partners' Capital Account, Contributions	us-gaap_PartnersCapitalAccountContributions	1,285
Common Class A [Member] | Retained Earnings [Member]
Stock Repurchased and Retired During Period, Value	us-gaap_StockRepurchasedAndRetiredDuringPeriodValue	15,169
Common Class B [Member] | Common Stock [Member]
Partners' Capital Account, Contributions	us-gaap_PartnersCapitalAccountContributions	$ 57