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EX-31.2 - EXHIBIT - Southcross Energy Partners, L.P.a2014q310-qex312.htm
EX-10.4 - EXHIBIT - Southcross Energy Partners, L.P.a2014q310-qex104.htm
EX-32.1 - EXHIBIT - Southcross Energy Partners, L.P.a2014q310-qex321.htm
EX-31.1 - EXHIBIT - Southcross Energy Partners, L.P.a2014q310-qex311.htm
EXCEL - IDEA: XBRL DOCUMENT - Southcross Energy Partners, L.P.Financial_Report.xls
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
 
(Mark One)
 
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended September 30, 2014
 
OR
 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from             to             
 
Commission File Number: 001-35719
 
Southcross Energy Partners, L.P.
(Exact name of registrant as specified in its charter)
 
DELAWARE
 
45-5045230
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
1700 Pacific Avenue, Suite 2900
Dallas, TX
 
75201
(Address of principal executive offices)
 
(Zip Code)
 
(214) 979-3720
(Registrant’s telephone number, including area code)
 
 
(Former name, former address and former fiscal year, if changed since last report)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer o
 
Accelerated filer x
 
 
 
Non-accelerated filer o
(Do not check if a smaller reporting company)
 
Smaller reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý
 
Indicate the number of units outstanding of the issuer’s classes of common units, subordinated units and Class B Convertible Units, as of the latest practicable date:
 
As of November 7, 2014, the registrant has 23,800,943 common units outstanding, 12,213,713 subordinated units outstanding and 14,633,000 Class B Convertible Units outstanding.  Our common units trade on the NYSE under the symbol “SXE.”



Commonly Used Terms
 
As generally used in the energy industry and in this Quarterly Report on Form 10-Q, the following terms have the following meanings:
 
/d: Per day

/gal: Per gallon
 
Bbls: Barrels
 
Condensate: Hydrocarbons that are produced from natural gas reservoirs but remain liquid at normal temperature and pressure
 
MMBtu: One million British thermal units
 
Mcf: One thousand cubic feet
 
Mgal: One thousand gallons
 
MMcf: One million cubic feet
 
NGLs: Natural gas liquids, which consist primarily of ethane, propane, isobutane, normal butane, natural gasoline and stabilized condensate
 
Residue gas: Pipeline quality natural gas remaining after natural gas is processed and NGLs and other matters are removed
 
Rich gas: Natural gas that is high in NGL content
 
Throughput: The volume of natural gas and NGLs transported or passing through a pipeline, plant, terminal or other facility
 
y-grade: Commingled mix of NGL components extracted via natural gas processing normally consisting of ethane, propane, isobutane, normal butane and natural gasoline

2


FORM 10-Q
TABLE OF CONTENTS
Southcross Energy Partners, L.P.
 
 
 
 
 
 
 
 
 
 
Condensed Consolidated Balance Sheets as of  September 30, 2014 and December 31, 2013
 
 
 
 
Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2014 and 2013
 
 
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2014 and 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

3


FORWARD-LOOKING INFORMATION
 
Investors are cautioned that certain statements contained in this report as well as in periodic press releases and oral statements made by our management team during our presentations are “forward-looking” statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will continue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would” and “could.” In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us or our subsidiaries, are also forward-looking statements. These forward-looking statements involve external risks and uncertainties, including, but not limited to, those described under the sections entitled “Risk Factors” in our 2013 Annual Report on Form 10-K and “Update to Risk Factors” included in our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014.
 
Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond the control of our management team. All forward-looking statements in this report and subsequent written and oral forward-looking statements attributable to us, or to persons acting on our behalf, are expressly qualified in their entirety by these risks and uncertainties. These risks and uncertainties include, among others:
 
the volatility of natural gas, crude oil and NGL prices and the price and demand of products derived from these commodities;
competitive conditions in our industry and the extent and success of producers increasing production or replacing declining production and our success in obtaining new sources of supply;
industry conditions and supply of pipelines, processing and fractionation capacity relative to available natural gas from producers;
our dependence upon a relatively limited number of customers for a significant portion of our revenues;
actions taken, inactions or non-performance by third parties, including suppliers, contractors, operators, processors, transporters and customers;
our ability to effectively recover NGLs at a rate equal to or greater than our contracted rates with customers;
our ability to produce and market NGLs at the anticipated differential to NGL index pricing;
our access to markets enabling us to match pricing indices for purchases and sales of natural gas and NGLs;
our ability to complete projects within budget and on schedule, including but not limited to, timely receipt of necessary government approvals and permits, our ability to control the costs of construction and other factors that may impact projects;
our ability to consummate acquisitions, successfully integrate the acquired businesses and realize anticipated cost savings and other synergies from any acquisitions, including with respect to our acquisition of the TexStar Rich Gas System (as defined in Note 1 to our condensed consolidated financial statements);
our ability to manage over time changing exposure to commodity price risk;
the effectiveness of our hedging activities or our decisions not to undertake hedging activities;
our access to financing and ability to remain in compliance with our financing covenants;
our ability to generate sufficient operating cash flow to fund our quarterly distributions;
changes in general economic conditions;
the effects of downtime associated with our assets or the assets of third parties interconnected with our systems;
operating hazards, fires, natural disasters, weather-related delays, casualty losses and other matters beyond our control;
the failure of our processing and fractionation plants to perform as expected, including outages for unscheduled maintenance or repair;
the effects of laws and governmental regulations and policies;
the effects of existing and future litigation; and
other financial, operational and legal risks and uncertainties detailed from time to time in our filings with the U.S. Securities and Exchange Commission.
 
Developments in any of these areas could cause actual results to differ materially from those anticipated or projected, affect our ability to maintain distribution levels and/or access necessary financial markets or cause a significant reduction in the market price of our common units.
 
The foregoing list of risks and uncertainties may not contain all of the risks and uncertainties that could affect us. In addition, in light of these risks and uncertainties, the matters referred to in the forward-looking statements contained in this report may not, in fact, occur. Accordingly, undue reliance should not be placed on these statements. We undertake no

4


obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as otherwise required by law.

5


PART I — FINANCIAL INFORMATION
 
Item 1. Financial Statements.
 
SOUTHCROSS ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except for unit data)
(Unaudited)

ASSETS
 
September 30, 2014
 
December 31, 2013
 
 

 
 

Current assets:
 

 
 

Cash and cash equivalents
$
1,823

 
$
3,349

Trade accounts receivable
68,583

 
57,669

Accounts receivable - affiliates
6,950

 

Prepaid expenses
3,589

 
3,061

Other current assets
5,732

 
5,105

Total current assets
86,677

 
69,184


 
 
 
Property, plant and equipment, net
947,928

 
575,795

Intangible assets, net
1,525

 
1,568

Investments in joint ventures
148,848

 

Other assets
19,951

 
5,768

Total assets
$
1,204,929

 
$
652,315

 
See accompanying notes.




























6




SOUTHCROSS ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except for unit data)
(Unaudited)

LIABILITIES, PREFERRED UNITS AND PARTNERS’ CAPITAL
 
September 30, 2014
 
December 31, 2013
 
 
 
 

Current liabilities:
 
 
 

Accounts payable and accrued liabilities
$
96,679

 
$
62,451

Accounts payable - affiliates
4,977

 

Other current liabilities
15,230

 
5,344

Total current liabilities
116,886

 
67,795



 

Long-term debt
457,875

 
267,300

Other non-current liabilities
990

 
1,692

Total liabilities
575,751

 
336,787


 
 

Commitments and contingencies (Note 8)


 


 
 

Series A Convertible preferred units (1,769,915 units issued and outstanding as of December 31, 2013)

 
40,504


 
 

Partners' capital:
 
 

Common units (25,179,351 and 13,963,713 units authorized; 23,800,943 and 12,253,985 units outstanding as of September 30, 2014 and December 31, 2013, respectively)
271,293

 
169,141

Class B Convertible units (14,633,000 units authorized, issued and outstanding as of September 30, 2014)
294,894

 

Subordinated units (12,213,713 units authorized, issued and outstanding as of September 30, 2014 and December 31, 2013)
50,194

 
99,726

General partner interest
12,797

 
6,367

Accumulated other comprehensive loss

 
(210
)
Total partners' capital
629,178

 
275,024

Total liabilities, preferred units and partners' capital
$
1,204,929

 
$
652,315


See accompanying notes.




7


SOUTHCROSS ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except for unit and per unit data)
(Unaudited)
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Revenues:
 
 
 
 
 
 
 
Revenues
$
205,203

 
$
160,629

 
$
613,857

 
$
459,583

Revenues - affiliates
6,290

 

 
6,290

 

Total revenues
211,493

 
160,629

 
620,147

 
459,583

 
 
 
 
 
 
 
 
Expenses:
 

 
 
 
 

 
 

Cost of natural gas and liquids sold
180,562

 
135,416

 
535,791

 
394,212

Operations and maintenance
16,889

 
10,896

 
39,494

 
31,069

Depreciation and amortization
11,629

 
9,447

 
29,135

 
24,958

General and administrative
14,926

 
5,227

 
27,722

 
16,850

Impairment of assets
1,556

 

 
1,556

 

Loss on sale of assets, net of gains
334

 

 
292

 

Total expenses
225,896

 
160,986

 
633,990

 
467,089

 
 
 
 
 
 
 
 
Loss from operations
(14,403
)
 
(357
)
 
(13,843
)
 
(7,506
)
Other income (expense):


 


 


 


Equity in losses of joint venture investments
(3,308
)
 

 
(3,308
)
 

Interest expense
(4,596
)
 
(3,587
)
 
(9,340
)
 
(8,735
)
Loss on extinguishment of debt
(2,316
)
 

 
(2,316
)
 

Other expense
(86
)
 

 
(86
)
 

Total other expense
(10,306
)
 
(3,587
)
 
(15,050
)
 
(8,735
)
Loss before income tax expense
(24,709
)
 
(3,944
)
 
(28,893
)
 
(16,241
)
Income tax expense
(69
)
 
(125
)
 
(133
)
 
(404
)
Net loss
(24,778
)
 
(4,069
)
 
(29,026
)
 
(16,645
)
Series A Preferred Unit fair value adjustment
424

 
4,667

 
(4,596
)
 

Series A Preferred Unit in-kind distribution

 
(696
)
 
(534
)
 
(1,255
)
General partner Unit in-kind distribution
(112
)
 

 
(123
)
 

Net loss attributable to partners
(24,466
)
 
(98
)
 
(34,279
)
 
(17,900
)
 
 
 
 
 
 
 
 
General partner's interest in net loss attributable to partners
(523
)
 
(81
)
 
(622
)
 
(334
)
Limited partners' Class B Convertible interest in net loss attributable to partners
(6,778
)
 

 
(6,778
)
 

Limited partners' interest in net loss attributable to partners
$
(17,165
)
 
$
(17
)
 
$
(26,879
)
 
$
(17,566
)
 
 

 
 
 
 
 
 
Earnings per unit and distributions declared
 
 
 
 
 
 
 
Weighted average number of limited partner common units outstanding
22,925,979

 
12,222,692

 
20,911,472

 
12,219,699

Income (loss) per common unit
$
(0.49
)
 
$
0.19

 
$
(0.91
)
 
$
(0.72
)
Diluted loss per common unit
$
(0.49
)
 
$
(0.14
)
 
$
(0.91
)
 
$
(0.72
)
Distributions declared per common unit
$
0.40

 
$
0.40

 
$
1.20

 
$
1.20

Weighted average number of limited partner subordinated units outstanding
12,213,713

 
12,213,713

 
12,213,713

 
12,213,713

Loss per subordinated unit
$
(0.49
)
 
$
(0.19
)
 
$
(0.64
)
 
$
(0.72
)
 

8


See accompanying notes.

9


SOUTHCROSS ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(In thousands)
(Unaudited)
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Net loss
$
(24,778
)
 
$
(4,069
)
 
$
(29,026
)
 
$
(16,645
)
Other comprehensive income (loss):
 

 
 

 
 

 
 

Hedging losses reclassified to earnings and recognized in interest expense

 
108

 
221

 
302

Adjustment in fair value of derivatives

 
(82
)
 
(11
)
 
(112
)
Total other comprehensive income

 
26

 
210

 
190

Comprehensive loss
$
(24,778
)
 
$
(4,043
)
 
$
(28,816
)
 
$
(16,455
)
 
See accompanying notes.

10


SOUTHCROSS ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited) 
 
Nine Months Ended September 30,
 
2014
 
2013
Cash flows from operating activities:
 
 
 
Net loss
$
(29,026
)
 
$
(16,645
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Depreciation and amortization
29,135

 
24,958

Unit-based compensation
10,837

 
1,645

Amortization and write-off of deferred financing costs
3,596

 
947

Loss on sale of assets, net of gains
292

 

Unrealized loss on financial instruments
539

 

Equity in losses of joint venture investments
3,308

 

Impairment of assets
1,556

 

Other, net
81

 
(63
)
Changes in operating assets and liabilities:
 
 
 
Trade accounts receivable, including affiliates
(12,009
)
 
(1,191
)
Prepaid expenses and other current assets
(1,066
)
 
(335
)
Other non-current assets
(32
)
 
(60
)
Accounts payable and accrued liabilities
10,043

 
(7,502
)
Other liabilities
4,046

 
1,708

Net cash provided by operating activities
21,300

 
3,462

Cash flows from investing activities:
 
 
 
Capital expenditures
(85,892
)
 
(86,149
)
Expenditures for assets subject to property damage claims, net of insurance proceeds and deductibles
(796
)
 
(2,716
)
Proceeds from sales of assets
1,758

 
45

Investment contribution to joint venture investments
(105
)
 

TexStar Rich Gas System acquisition from affiliate
(79,955
)
 

Onyx Pipelines acquisition
(38,636
)
 

Net cash used in investing activities
(203,626
)
 
(88,820
)
Cash flows from financing activities:


 


Proceeds from issuance of common units, net
144,671

 

Borrowings under our credit facility
184,000

 
107,500

Borrowings under our term loan agreement
450,000

 

Repayments under our credit facility
(442,300
)
 
(40,000
)
Repayments under our term loan agreement
(1,125
)
 

Payments on capital lease obligations
(454
)
 
(398
)
Financing costs
(17,716
)
 
(2,139
)
Proceeds from issuance of Series A Convertible preferred units, net of issuance costs

 
38,832

Contributions from general partner
9,967

 
800

Payments of distributions and distribution equivalent rights
(42,711
)
 
(25,941
)
Assumption and repayment of debt in TexStar Rich Gas System Transaction
(100,000
)
 

Tax withholdings on unit-based compensation vested units
(3,532
)
 

Net cash provided by financing activities
180,800

 
78,654

Net decrease in cash and cash equivalents
(1,526
)
 
(6,704
)
Cash and cash equivalents — Beginning of period
$
3,349

 
$
7,490

Cash and cash equivalents — End of period
$
1,823

 
$
786


See accompanying notes.

11


SOUTHCROSS ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL
(In thousands)
(Unaudited) 
 

 
Partners' Capital



 
Limited Partners



Accumulated Other Comprehensive Loss




Common

Class B Convertible
 
Subordinated

General Partner


Total
BALANCE - December 31, 2013
$
169,141

 
$

 
$
99,726

 
$
6,367

 
$
(210
)
 
$
275,024

Net loss

(14,102
)
 
(6,778
)
 
(7,565
)
 
(581
)
 

 
(29,026
)
Issuance of common units, net

144,671

 

 

 

 

 
144,671

Issuance of Class B Convertible units, net
 

 
324,413

 

 

 

 
324,413

Consideration paid in excess of purchase price for the TexStar Rich Gas System

(45,880
)
 
(28,208
)
 
(23,544
)
 
(1,993
)
 

 
(99,625
)
Class B Convertible unit in-kind distribution

(3,533
)
 
5,467

 
(1,824
)
 
(110
)
 

 

Unit-based compensation on long-term incentive plan

9,236

 

 

 

 

 
9,236

Series A Convertible preferred conversion into common units

45,624

 

 

 

 

 
45,624

Series A Convertible preferred unit in-kind distribution and fair value adjustments

(3,126
)
 

 
(1,897
)
 
(107
)
 

 
(5,130
)
Contributions from general partner


 

 

 
9,967

 

 
9,967

Cash distributions and distribution equivalent rights paid

(26,566
)
 

 
(14,657
)
 
(869
)
 

 
(42,092
)
Accrued distribution equivalent rights on long-term incentive plan

(562
)
 

 

 

 

 
(562
)
Tax withholdings on unit-based compensation vested units
 
(3,532
)
 

 

 

 

 
(3,532
)
General partner unit in-kind distribution
 
(78
)
 

 
(45
)
 
123

 

 

Net effect of cash flow hedges
 

 

 

 

 
210

 
210

BALANCE - September 30, 2014
$
271,293

 
$
294,894

 
$
50,194

 
$
12,797

 
$

 
$
629,178


12


 
 
Partners' Capital
 
 
 
 
Limited Partners
 
 
 
Accumulated Other Comprehensive Loss
 
 
 
 
Common
 
Subordinated
 
General Partner
 
 
Total
BALANCE - December 31, 2012
$
194,365

 
$
125,951

 
$
6,628

 
$
(477
)
 
$
326,467

Net loss
 
(8,172
)
 
(8,164
)
 
(309
)
 

 
(16,645
)
Unit-based compensation on long-term incentive plan
 
1,206

 

 

 

 
1,206

Series A Convertible preferred unit in-kind distribution
 
(615
)
 
(615
)
 
(25
)
 

 
(1,255
)
Contributions from general partner
 

 

 
800

 

 
800

Cash distributions and distribution equivalent rights paid
 
(12,709
)
 
(12,703
)
 
(529
)
 

 
(25,941
)
Accrued distribution equivalent rights on long-term incentive plan
 
(191
)
 

 

 

 
(191
)
General partner unit in-kind distribution
 
(13
)
 
(12
)
 
25

 

 

Net effect of cash flow hedges
 

 

 

 
190

 
190

BALANCE - September 30, 2013
$
173,871

 
$
104,457

 
$
6,590

 
$
(287
)
 
$
284,631


See accompanying notes.

13


SOUTHCROSS ENERGY PARTNERS, L.P.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
 
1. ORGANIZATION AND DESCRIPTION OF BUSINESS
 
Organization
 
Southcross Energy Partners, L.P. (the "Partnership," "Southcross," "we," "our" or "us") is a Delaware limited partnership formed in April 2012. Our common units are listed on the New York Stock Exchange under the symbol “SXE.”

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, 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”).

Holdings Transaction

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 owns 100% of our General Partner (and therefore controls us), all of our subordinated units, a portion of our common units, as well as 100% of the equity of TexStar. Charlesbank, EIG Global Energy Partners (“EIG”) and Tailwater Capital LLC (“Tailwater”) (collectively, the “Sponsors”) each indirectly own approximately one-third of Holdings.

TexStar Rich Gas System Transaction

Contemporaneously with the closing of the Holdings Transaction, TexStar contributed to us its gathering and processing assets (the “TexStar Rich Gas System”), which was 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, 3, 7, 10, 11 and 14.
 
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 with our 2013 Annual Report on Form 10-K. The condensed consolidated financial statements as of September 30, 2014 and December 31, 2013, and for the three and nine months ended September 30, 2014 and 2013, are unaudited and have been prepared on the same basis as the audited financial statements included in our 2013 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.


14


The condensed 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 discussed further in Note 2. The condensed consolidated financial statements also reflect the TexStar Rich Gas System Transaction and the related operating results beginning on August 4, 2014.

As a result of the Holdings Transaction, Holdings acquired a controlling equity interest in the Partnership which is being 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 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, the date on which the Holdings Transaction and the TexStar Rich Gas System Transaction closed.
 
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 2013 Annual Report on Form 10-K.
 
We evaluate events that occur after the balance sheet date, but before the financial statements are issued, for potential recognition or disclosure. Based on the evaluation, we determined that there were no material subsequent events for recognition or disclosure other than those disclosed in this report.
 
Significant Accounting Policies
 
During the third quarter of 2014, there was an update to our significant accounting policies as described in our 2013 Annual Report on Form 10-K.

As a result of the TexStar Rich Gas System Transaction, we now hold equity interests in three joint venture entities. We own a 50% or less 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 we 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 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 14.
 
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.

The Financial Accounting Standard Board (“FASB”) and the International Accounting Standard Board (“IASB”) jointly issued a comprehensive new revenue recognition standard that will supersede substantially all existing revenue recognition guidance under GAAP and International Financial Reporting Standards (“IFRS”). 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.


15


The FASB and the IASB jointly issued a new discontinued operations standard that will update existing discontinued operations guidance under GAAP and IFRS. The standard’s main updates to previous guidance are that it will raise the threshold for disposals to qualify as discontinued operations, continuing cash flows and continuing involvement with disposed components will no longer be considered in determining whether a transaction qualifies as a discontinued operation and additional disclosures surrounding disposals of both discontinued operations and certain other disposals that do not meet the new definition will be required. We are required to adopt this standard beginning in the first quarter of 2015.

The FASB issued a new going concern standard 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.

2. ACQUISITIONS

TexStar Rich Gas System Transaction. On August 4, 2014, we acquired 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 new term loan agreement) and issued 14,633,000 of our 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. These pipelines are operated under split-capacity arrangements within joint ventures with Atlas Pipeline Partners, L.P. The initial accounting for the transaction is not complete because the information necessary for determining certain working capital balances is still in process.

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
 
$
295

Property, plant and equipment
 
255,220

Investments in joint ventures(2)
 
152,050

Total assets contributed
 
407,565

Total liabilities assumed (3)
 
(102,776
)
Net identifiable assets contributed
 
$
304,789

Consideration paid in excess of net assets contributed
 
$
99,625

Allocation of reduction to partners' capital
 
 
Common limited partner interest
$
45,880

 
Class B Convertible limited partner interest
28,208

 
Subordinated limited partner interest
23,544

 
General Partner interest
1,993

 
Total reduction to partners' capital
 
$
99,625

 
(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 14.
(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.


16


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

Pro Forma Financial Information for Onyx Pipelines Acquisition. The following unaudited pro forma financial information for the three and nine months ended September 30, 2013 and the nine months ended September 30, 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
 
Nine Months Ended September 30,
 
September 30, 2013
 
2014
 
2013
Total revenue
$
161,777

 
$
620,796

 
$
462,818

Net loss
(4,547
)
 
(29,104
)
 
(18,533
)
Net income (loss) attributable to common unitholders
2,067

 
(19,132
)
 
(9,794
)
Net income (loss) per common unit
0.14

 
(0.91
)
 
(0.67
)
Diluted income (loss) per common unit
0.13

 
(0.91
)
 
(0.67
)
Net loss attributable to subordinated unitholders
(2,553
)
 
(7,823
)
 
(9,624
)
Net loss per subordinated unit—(basic and diluted)
(0.21
)
 
(0.64
)
 
(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 three and nine months ended September 30, 2014, the Onyx pipelines business contributed $1.3 million and $3.0 million, respectively, in revenues and $0.5 million and $0.9 million, respectively, in net income to our statements of operations.
3. TRANSACTION-RELATED COSTS

During the three and nine months ended September 30, 2014, the Partnership recognized $10.5 million and $10.8 million, respectively, of transaction-related costs in connection with the Onyx acquisition, the Holdings Transaction and the TexStar Rich Gas System Transaction, which are recorded in operations and maintenance and general and administrative expenses. For the three months ended September 30, 2014, these costs include (a) $7.1 million related to the accelerated vesting of the LTIP awards (as defined in Note 12) due to the change in control as further discussed in Note 12, (b) $1.5 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 12, (c) $1.3 million of advisory, audit and legal fees and (d) $0.6 million of charges associated with employees’ severance. The additional $0.3 million incurred for the nine months ended September 30, 2014 relates to

17


professional fees associated with the Onyx acquisition. As of September 30, 2014, $3.0 million of these costs were included in accounts payable and accrued liabilities in the balance sheet, which we expect to pay in the fourth quarter of 2014 or the first quarter of 2015. In addition, the Partnership expects to incur additional costs relating to integration and other activities during the fourth quarter of 2014 and throughout 2015.

4. 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 and nine months ended September 30, 2014 and 2013 (in thousands, except unit and per unit data): 
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2014
 
2013
 
2014
 
2013
Net loss
 
$
(24,778
)
 
$
(4,069
)
 
$
(29,026
)
 
$
(16,645
)
Series A Preferred Unit fair value adjustment (1)
 
424

 
4,667

 
(4,596
)
 

Series A Preferred Unit in-kind distribution
 
$

 
$
(696
)
 
$
(534
)
 
$
(1,255
)
General partner Unit in-kind distribution
 
$
(112
)
 
$

 
$
(123
)
 
$

    Net loss attributable to partners
 
$
(24,466
)
 
$
(98
)
 
$
(34,279
)
 
$
(17,900
)
 
 
 
 
 
 
 
 
 
General partner's interest (2)
 
$
(523
)
 
$
(81
)
 
$
(622
)
 
$
(334
)
Class B Convertible interest (2)
 
(6,778
)
 

 
(6,778
)
 

Limited partners' interest (2)
 
 
 
 
 
 
 
 
    Common
 
$
(11,156
)
 
$
2,323

 
$
(19,084
)
 
$
(8,784
)
    Subordinated
 
$
(6,009
)
 
$
(2,340
)
 
$
(7,795
)
 
$
(8,782
)

(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 September 30, 2014 and 2013 and increased the net loss attributable to partners for the nine months ended September 30, 2014 in the calculation of earnings per unit (see Note 9).
(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. Class B Convertible interest is calculated based on the allocation of only net losses for the period.
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Common Units
 
2014
 
2013
 
2014
 
2013
Interest in net income (loss)
 
$
(11,156
)
 
$
2,323

 
$
(19,084
)
 
$
(8,784
)
Effect of dilutive units - numerator (1)
 

 
(4,326
)
 

 

    Dilutive interest in net loss
 
$
(11,156
)
 
$
(2,003
)
 
$
(19,084
)
 
$
(8,784
)
 
 
 
 
 
 
 
 
 
Weighted-average units - basic
 
22,925,979

 
12,222,692

 
20,911,472

 
12,219,699

Effect of dilutive units - denominator (2)
 

 
1,767,445

 

 

    Weighted-average units - dilutive
 
22,925,979

 
13,990,137

 
20,911,472

 
12,219,699

 
 
 
 
 
 
 
 
 
Basic net income (loss) per common unit
 
$
(0.49
)
 
$
0.19

 
$
(0.91
)
 
$
(0.72
)
 
 
 
 
 
 
 
 
 
Diluted net loss per common unit
 
$
(0.49
)
 
$
(0.14
)
 
$
(0.91
)
 
$
(0.72
)


18


 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Subordinated Units
 
2014
 
2013
 
2014
 
2013
Interest in net loss
 
$
(6,009
)
 
$
(2,340
)
 
$
(7,795
)
 
$
(8,782
)
Effect of dilutive units - numerator(1)
 

 

 

 

    Dilutive interest in net loss
 
$
(6,009
)
 
$
(2,340
)
 
$
(7,795
)
 
$
(8,782
)
 
 
 
 
 
 
 
 
 
Weighted-average units - basic
 
12,213,713

 
12,213,713

 
12,213,713

 
12,213,713

Effect of dilutive units - denominator(1)
 

 

 

 

    Weighted-average units - dilutive
 
12,213,713

 
12,213,713

 
12,213,713

 
12,213,713

 
 
 
 
 
 
 
 
 
Basic and diluted net loss per subordinated unit
 
$
(0.49
)
 
$
(0.19
)
 
$
(0.64
)
 
$
(0.72
)

(1) Because we had a net loss for the three and nine months ended September 30, 2014 and nine months ended September 30, 2013 for the common units, and for the three and nine months ended September 30, 2014 and the three and nine months ended September 30, 2013 for the subordinated units, the effect of the dilutive units would be anti-dilutive to the per unit calculation. Therefore, the weighted average units outstanding are the same for basic and dilutive net loss per unit for those periods. The weighted average units that would be included in the computation of diluted per unit amounts in accordance with the treasury stock method were 32,757,204 and 25,447,215 for the three and nine months ended September 30, 2014, respectively.
(2) The weighted average units included in the computation of diluted per unit amounts were 27,972 unvested awards granted under our long-term incentive plan and 1,739,473 Series A Preferred Units for the three months ended September 30, 2013. The weighted average units that were not included in the computation of diluted per unit amounts were 20,221 unvested awards granted under our long-term incentive plan and 1,052,329 Series A Preferred Units for the nine months ended September 30, 2013. Diluted net income per limited partner unit reflects the potential dilution that could occur if securities or agreements to issue common units, such as awards under the LTIP (as defined in Note 12), were exercised, settled or converted into common units. When it is determined that potential common units resulting from an award should be included in the diluted net income per limited partner unit calculation, the impact is reflected by applying the treasury stock method.
 
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 9). 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 and nine months ended September 30, 2014.
 
Distributions
 
Our agreement of limited partnership, which was amended and restated for the third time 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 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.
 
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

19


Credit Facility (as defined in Note 7) (see Notes 7 and 9). 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 from the date of our initial public offering 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
Preferred Unit
Distributions to Series A Preferred Holders
 
In-Kind 
Series A
Preferred
Distributions
Value
(2)
 
In-Kind 
Unit
Distribution
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. 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”). 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 10.

The following table represents the PIK distribution earned on the Class B Convertible Units for periods after August 4, 2014 and ended September 30, 2014 (in thousands, except per unit and in-kind distribution units):

20


Payment Date
 
Attributable to the Quarter Ended
 
Per Unit Distribution
 
In-Kind Class B Convertible Unit
Distributions to Class B Convertible Holders
 
In-Kind 
Class B Convertible Distributions
Value
(1)
 
In-Kind 
Unit
Distribution
to General 
Partner
 
In-Kind General Partner Distribution Value(1)
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 from the date of our initial public offering (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
 
 
 
 
 
 
 
 
 
 
 
 
November 14, 2014
 
September 30, 2014
 
$
0.40

(1) 
$
9,520

 
$

 
$
413

 
$
9,933

August 14, 2014
 
June 30, 2014
 
0.40

(1) 
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 in Note 12) as a result of the Holdings Transaction (see Notes 1, 9 and 12).
(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 initial public offering on November 7, 2012.

5. 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 swaps.

21


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 Swaps
We manage a portion of our interest rate risk through interest rate swaps. In March 2012, we terminated an interest rate cap contract and entered into an interest rate swap contract with Wells Fargo, N.A. The interest rate swap 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 three and nine months ended September 30, 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 7). 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. Beginning June 30, 2014, 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.

The fair value of our interest rate swaps is determined based on a discounted cash flow method using the contractual terms of the swaps. The floating coupon rate is based on observable rates consistent with the frequency of the interest cash flows.
 
We have elected to present our interest rate swaps net on the balance sheets. There was no effect of offsetting on the balance sheets as of September 30, 2014 or December 31, 2013. Our interest rate swap position was as follows (in thousands):
 
 
 
 
 
 
 
 
Estimated Fair Value
Notional Amount
 
Fixed Rate
 
Effective Date
 
Maturity Date
 
September 30, 2014
$
140,000

 
0.327
%
 
June 30, 2014
 
June 30, 2015
 
$
(140
)
50,000

 
1.198
%
 
September 30, 2014
 
June 30, 2016
 
(31
)
50,000

 
1.196
%
 
September 30, 2014
 
June 30, 2016
 
(30
)
 
 
 
 
 
 
 
 
$
(201
)

The fair values of our interest rate swap liabilities were as follows (in thousands):

22


 
Significant Other Observable Inputs (Level 2)
 
Fair Value Measurement as of
 
September 30, 2014
 
December 31, 2013
Current interest rate swap liabilities
$
175

 
$
263

Non-current interest rate swap liabilities
26

 

Total interest rate swap liabilities
$
201

 
$
263

 
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 September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Change in value recognized in other comprehensive loss - effective portion
$

 
$
(82
)
 
$
(11
)
 
$
(112
)
Loss reclassified from accumulated other comprehensive loss to interest expense

 
108

 
221

 
302

 
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 September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Realized loss on interest rate swap derivatives
$
(74
)
 
$
(27
)
 
$
(127
)
 
$
(81
)
Unrealized loss on interest rate swap derivatives
(21
)
 

 
(201
)
 

 
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 for the outstanding month-ahead swap contracts as of September 30, 2014 and December 31, 2013 was 40,000 MMBtu per day and 33,722 MMBtu per day, respectively. 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 September 30, 2014 or December 31, 2013. The effect of offsetting on the balance sheets were as follows (in thousands):
 
 
September 30, 2014
 
December 31, 2013
 
 
Other Current Assets
 
Other Current Liabilities
 
Other Current Assets
 
Other Current Liabilities
Gross amounts of recognized assets (liabilities)
 
$

 
$
(218
)
 
$
140

 
$
(20
)
Gross amounts offset on the balance sheets
 

 

 
(20
)
 
20

Net amount
 
$

 
$
(218
)
 
$
120

 
$

The realized and unrealized gain/loss on these derivatives, recognized in revenues in our statements of operations, were as follows (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Realized gain (loss) on commodity swap derivatives
$
213

 
$
(93
)
 
$
(875
)
 
$
(149
)
Unrealized loss on commodity swap derivatives
(207
)
 

 
(338
)
 


23


6. LONG-LIVED ASSETS
Property, Plant and Equipment
Property, plant and equipment consisted of the following (in thousands):
 
Estimated
Useful Life (yrs)
 
September 30, 2014
 
December 31, 2013
Pipelines
30
 
$
393,131

 
$
344,721

Gas processing, treating and other plants
15
 
481,939

 
254,133

Compressors
7
 
37,936

 
20,030

Rights of way and easements
15
 
26,338

 
20,729

Furniture, fixtures and equipment
5
 
3,610

 
3,347

Capital lease vehicles
3-5
 
1,946

 
1,396

    Total property, plant and equipment
 
 
944,900

 
644,356

Accumulated depreciation and amortization
 
 
(118,565
)
 
(79,908
)
    Total
 
 
826,335

 
564,448

Construction in progress
 
 
96,090

 
6,039

Land and other
 
 
25,503

 
5,308

    Property, plant and equipment, net
 
 
$
947,928

 
$
575,795

 
Depreciation is provided using the straight-line method based on the estimated useful life of each asset. 
 
In January 2013, we shut down our Gregory facility to perform extensive turnaround maintenance activities and to connect additional equipment to enhance NGL recoveries. As the turnaround maintenance was nearing completion in January 2013, we experienced a fire at this facility. In connection with the fire, as of September 30, 2014, we spent $5.8 million to return the facility to service and filed an insurance claim related to these costs. We recovered $1.0 million in 2013 and $0.6 million in 2014 from insurance proceeds for this loss and believe it is probable that we will recover the remaining costs, less a $0.3 million deductible, under our insurance policies. As of September 30, 2014, we have $3.9 million related to this recovery included in current assets in our balance sheet.
 
Intangible Assets

Intangible assets of $1.5 million and $1.6 million as of September 30, 2014 and December 31, 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.

7. LONG-TERM DEBT 

Our outstanding debt and related information at September 30, 2014 and December 31, 2013 are as follows (in thousands):
 
September 30, 2014
 
December 31, 2013
Credit facility
$
9,000


$
267,300

Term loans
448,875

 

Total long-term debt
$
457,875

 
$
267,300

Outstanding letters of credit
$
23,030

 
$
31,260

Remaining unused borrowings
$
167,970

 
$
69

 
Three Months Ended September 30,

Nine Months Ended September 30,
 
2014

2013

2014

2013
Weighted average interest rate
4.8
%
 
4.8
%
 
4.2
%
 
4.3
%
Average outstanding borrowings
$
372,072

 
$
254,200

 
$
252,005

 
$
238,900

Maximum borrowings
$
465,000

 
$
258,500

 
$
465,000

 
$
258,500


Previous Credit Facility

24


 
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, the January 2013 fire at our Gregory facility and contractual disputes with a former third party processor. 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 again 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 a new term loan agreement.

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.

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 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 is set at (i) 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) 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 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

25


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. 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 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).

8. COMMITMENTS AND CONTINGENCIES
 
Legal Matters
 
In March 2013, one of our subsidiaries filed suit against Formosa Hydrocarbons Company, Inc. (“Formosa”). The lawsuit seeks recoveries of losses that we believe our subsidiary experienced as a result of the failure of Formosa to perform certain of its obligations under the gas processing and sales contract between the parties. Formosa filed a response generally denying our claims and filed counterclaims against our subsidiary claiming our affiliate breached the gas processing and sales contract and breached a related agreement between the parties for the supply by Formosa of residue gas to a third party on behalf of our subsidiary. Our subsidiary will defend itself vigorously against the counterclaims while continuing to pursue its own claims. A trial date in early 2015 is expected. We cannot predict the outcome of such litigation or the timing of any related recoveries or payments.
 
From time to time, we are party to certain legal or administrative proceedings that arise in the ordinary course and are incidental to our business. 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

26


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 $0.1 million and $0.4 million for the three and nine months ended September 30, 2014, respectively. We recorded amortization expense related to the capital leases of $0.1 million and $0.4 million for the three and nine months ended September 30, 2013, respectively. The capital lease obligation amounts included on the balance sheets were as follows (in thousands):
 
September 30, 2014
 
December 31, 2013
Other current liabilities
$
484

 
$
481

Other non-current liabilities
569

 
427

Total
$
1,053

 
$
908


Capital leases entered into during the three and nine months ended September 30, 2014 were $0.1 million and $0.6 million, respectively. Capital leases entered into during the three and nine months ended September 30, 2013 were $0.2 million and $1.4 million, respectively.

Operating Leases
 
We maintain operating leases in the ordinary course of business. 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 $0.6 million and $1.2 million for the three and nine months ended September 30, 2014, respectively. Expenses associated with operating leases were $0.4 million and $1.1 million for the three and nine months ended September 30, 2013, respectively.

Purchase Commitments
 
As of September 30, 2014, we had commitments of approximately $25.4 million for purchases of material and equipment related to our capital projects, primarily the construction of an addition to our pipeline system by approximately 45 miles into Webb County, Texas (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.
 
9. SERIES A PREFERRED UNITS
 
We entered into a Series A Convertible Preferred Unit Purchase Agreement (the “Purchase Agreement”) with Southcross Energy LLC, pursuant to which we issued and sold 1,715,000 Series A Preferred Units to Southcross Energy LLC during the second quarter of 2013 for a cash purchase price of $22.86 per unit, in a privately negotiated transaction (the “Private Placement”). Southcross Energy LLC sold 1,500,000 of these Series A Preferred Units to third parties during the second quarter of 2013. The Private Placement 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 7).

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.
 

27


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 the maximum redemption value was different than the fair value of the units at issuance. 
 
Voting Rights: The Series A Preferred Units were a class of voting equity security ranking 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 if a third party acquired majority ownership control of our General Partner or we sold substantially all of our assets, in either case 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.
 
10. PARTNERS’ CAPITAL
 
Ownership

Our units outstanding as of September 30, 2014 is as follows (in units):

 
 
 
Partners’ Capital
 
 
 
 
 
Southcross
 
 
 
 
 
 
 
 
 
Series A
 
Public
 
Energy LLC
 
Holdings
 
Class B
 
 
 
General
 
Preferred
 
Common
 
Common
 
Common
 
Convertible
 
Subordinated
 
Partner
Units outstanding as of December 31, 2013
1,769,915

 
10,390,272

 
1,863,713

 

 

 
12,213,713

 
534,638

Issuance of common units

 
9,200,000

 

 

 

 

 
187,755

Holdings Transaction

 

 
(1,863,713
)
 
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

 

 

 

 

 

 
311,233

Units outstanding as of September 30, 2014

 
21,684,543

 

 
2,116,400

 
14,633,000

 
12,213,713

 
1,033,626


Common Units