10-Q 1 a2014q310-qdoc.htm 10-Q 2014 Q3 10-Q Doc
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

28

In February 2014, we completed a public equity offering of 9,200,000 additional common units for $144.7 million, net of expenses, and received a capital contribution from our General Partner to maintain its 2.0% interest in us. 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.
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 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 12), 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

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.

The 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.

The 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.

Distributions 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 the 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 will 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, Holdings owns an approximate 39.8% 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 and Southcross Energy LLC is controlled by Charlesbank. The Holdings Transaction resulted in the Sponsors each indirectly owning approximately one-third of 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

29

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, 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.

General Partner Interests
 
Our general partner interests consisted of 1,033,626 and 534,638 general partner units as of September 30, 2014 and December 31, 2013, respectively. 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 9).
 
11. TRANSACTIONS WITH RELATED PARTIES
 
Charlesbank, EIG & Tailwater (the 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 person affiliated with Charlesbank, one person affiliated with EIG, one person affiliated with Tailwater and three outside directors. The seventh member of the board of directors of our General Partner and its chairman was selected by a majority of the other directors. David W. 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 September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Charlesbank
$
80

 
$
51

 
$
270

 
$
387

EIG
8

 
—

 
8

 
—

Tailwater
8

 
—

 
8

 
—

Total fees and expenses paid for director services to affiliated entities
$
96

 
$
51

 
$
286

 
$
387


Southcross Energy Partners GP, LLC (our General Partner)
 
Our General Partner does not receive a management fee or other compensation for its management of us. However, our General Partner and its affiliates are entitled to reimbursements for all expenses incurred on our behalf, including, among other items, compensation expense for all employees required to manage and operate our business. We incurred expenses related to these reimbursements as follows (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Reimbursements included in general and administrative expenses
$
3,076

 
$
2,624

 
$
9,057

 
$
7,564

Reimbursements included in operations and maintenance expenses
4,562

 
3,596

 
12,175

 
9,904

Total reimbursements to our General Partner and its affiliates
$
7,638

 
$
6,220

 
$
21,232

 
$
17,468


Compensation expense for services incurred by us on behalf of Southcross Energy LLC were billed to Southcross Energy LLC. For the three and nine months ended September 30, 2014, compensation expense, which was not incurred on our behalf, of $0.4 million and $0.7 million, respectively, was billed to Southcross Energy LLC.
 
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. 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

30

Series A Preferred Units, including those held by Southcross Energy LLC, were converted into common units on August 4, 2014. See Notes 1 and 9.
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 7. An affiliate of Wells Fargo Bank, N.A. is a member of the 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 and nine months ended September 30, 2014, we incurred costs, excluding interest, to Wells Fargo Bank, N.A. and its affiliates of $8.9 million and $9.1 million, respectively. During the three and nine months ended September 30, 2013, we incurred costs, excluding interest, to Wells Fargo Bank, N.A. and its affiliates of $0.4 million and $1.0 million, respectively. When incurred, these costs were capitalized to deferred financing costs (see Notes 7 and 17).

Other Transactions with Affiliates

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. 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 three and nine months ended September 30, 2014, the Partnership recorded revenues from affiliates of $6.3 million in accordance with the G&P Agreement and the NGL Agreement. Accounts receivable due from affiliates of $7.0 million as of September 30, 2014 is comprised of primarily (a) $3.1 million due from Holdings relating to gathering and processing services in the period and (b) $2.8 million due from T2 Cogen (as defined in Note 14) representing reimbursements for operating costs and equipment for this investment in joint venture. Accounts payable due to affiliates of $5.0 million as of September 30, 2014 is comprised of primarily (a) $3.0 million due to Holdings relating to reimbursements of insurance costs and capital costs and (b) $1.1 million due to T2 Cogen representing operational obligations for this investment in joint venture.
 
12. INCENTIVE COMPENSATION
Unit Based Compensation
Long-Term Incentive Plan
On November 7, 2012, and in connection with our initial public offering, we established our 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
Value at Grant Date
Unvested - December 31, 2013
182,673

 
$
22.55

  Granted units
776,821

 
19.82

  Forfeited units
(200
)
 
23.01

  Units recaptured for tax withholdings
(159,500
)
 
17.06

  Vested units
(325,551
)
 
17.45

Unvested - September 30, 2014
474,243

 
$
20.46

 

31

For the nine months ended September 30, 2014 and 2013, we granted awards under the LTIP with a grant date fair value of $15.4 million and $2.4 million, respectively, which we have classified as equity awards. As of September 30, 2014 and September 30, 2013, we had total unamortized compensation expense of $9.7 million and $4.1 million, respectively, related to these awards. The awards were expected to be amortized over a three-year vesting period from each equity awards’ 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 September 30, 2014 and September 30, 2013, we had 909,934 and 1,508,421 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 expense on our statements of operations (in thousands): 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Unit-based compensation
$
9,227

(1) 
$
552

 
$
10,837

(1) 
$
1,645

 
(1) This amount includes $7.1 million related to the accelerated vesting of the LTIP awards and $1.5 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 Equity Equivalent Units

In conjunction with the closing of the TexStar Rich Gas System Transaction, 15,000 outstanding Southcross Energy LLC equity equivalent units subject to change of control provisions vested on August 4, 2014. The Partnership recognized $1.5 million in general and administrative expenses in the statements of operations for the three and nine months ended September 30, 2014 in connection with the accelerated vesting of these equity equivalent units.
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 plans, subject to limits. We provide a matching contribution each payroll period equal to 100% of the employees’ contributions up to the lesser of 6% of each employee’s pay 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 September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Matching contributions expensed for employee savings plan
$
271

 
$
166

 
$
861

 
$
476


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

32

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 September 30, 2014, no awards had been granted under this plan.
13. REVENUES
 
We had revenues consisting of the following categories (in thousands): 

 
Three Months Ended September 30,

Nine Months Ended September 30,
 
2014

2013

2014

2013
Sales of natural gas
$
123,874

 
$
99,483

 
$
392,633

 
$
304,343

Sales of NGLs and condensate
65,046

 
45,916

 
171,201

 
112,128

Transportation, gathering and processing fees
22,466

 
15,124

 
55,860

 
42,644

Other
107

 
106

 
453

 
468

Total revenues
$
211,493

 
$
160,629

 
$
620,147

 
$
459,583

 
14. INVESTMENTS IN JOINT VENTURES

Assets acquired through the TexStar Rich Gas System Transaction include equity interests in three joint ventures. During 2012, 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):

 
Three and Nine Months Ended September 30, 2014
 
T2 Eagle Ford
 
T2 Cogen
 
T2 LaSalle
Revenue
$
516

 
$
410

 
$
229

Net loss
(3,234
)
 
(2,871
)
 
(1,021
)

The Partnership’s equity in losses of joint venture investments is comprised of the following for the three and nine months ended September 30, 2014 (in thousands):
 
Three and Nine Months Ended
 
September 30, 2014
T2 Eagle Ford
$
(1,618
)
T2 Cogen
(1,435
)
T2 LaSalle
(255
)
Equity in losses of joint venture investments
$
(3,308
)
The Partnership’s investments in joint ventures is comprised of the following as of September 30, 2014 (in thousands):
 
September 30, 2014
T2 Eagle Ford
$
110,152

T2 Cogen
18,994

T2 LaSalle
19,702

Investments in joint ventures
$
148,848



15. CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE
 

33

Our primary markets are in South Texas, Alabama and Mississippi. We have a concentration of revenues and trade accounts receivable due from customers engaged in the production, trading, distribution and marketing of natural gas and NGL products. These concentrations of customers may affect overall credit risk in that these customers may be affected similarly by changes in economic, regulatory or other factors. We analyze our customers’ historical financial and operational information before extending credit.
 
Our top ten customers for the three and nine months ended September 30, 2014 and 2013 represent the following percentages of consolidated revenue: 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Top ten customers
66.9
%
 
69.1
%
 
67.1
%
 
58.8
%
 
The percentage of total consolidated revenue for each customer that exceeded 10% of total revenues for the three and nine months ended September 30, 2014 and 2013 was as follows: 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Trafigura AG
15.7
%
 
13.1
%
 
13.6
%
 
N/A(1)

Sherwin Alumina Company
N/A(1)

 
12.0
%
 
10.6
%
 
12.3
%
 
(1) Information is not provided for periods for which the customer or producer was less than 10% of our consolidated revenue.
 
For the nine months ended September 30, 2014 and 2013, we did not experience significant non-payment for services. At September 30, 2014 and December 31, 2013, we did not record an allowance for uncollectible accounts receivable.
 
16. SUBSEQUENT EVENTS

Partnership Distributions

 On October 22, 2014, 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 November 14, 2014 to unitholders of record on November 5, 2014. In addition, on October 22, 2014, the board of directors of our General Partner declared a $0.3257 per unit distribution for the third quarter of 2014 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 November 14, 2014. 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. As a result of this election, Holdings will not receive distributions for the third quarter of 2014 on any of its subordinated units.


17. SUPPLEMENTAL INFORMATION


34

Supplemental Cash Flow Information (in thousands)
 
Nine Months Ended September 30,
 
2014
 
2013
Supplemental Disclosures:
 
 
 
Cash paid for interest, net of amounts capitalized
$
8,628

 
$
8,880

Cash received for tax refunds
205

 
95

Supplemental disclosures of non-cash investing and financing activities:


 


Accounts payable related to capital expenditures
23,144

 
34,238

Change in value recognized in other comprehensive income
11

 
112

Capital lease obligations
577

 
1,399

Accrued distribution equivalent rights on LTIP units
562

 
191

Series A Convertible preferred unit in-kind distributions and fair value adjustments
5,130

 
1,255

Class B Convertible unit issuance, net
324,413

 
—

Consideration paid in excess of purchase price for the TexStar Rich Gas System
99,625

 
—

Capitalization of Interest Cost
We capitalize interest on projects during their construction period. Once a project is placed in service, capitalized interest, as a component of the total cost of the construction, is depreciated over the estimated useful life of the asset constructed. We incurred the following interest costs (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Total interest costs
$
5,529

 
$
3,887

 
$
10,826

 
$
10,035

Capitalized interest included in property, plant and equipment, net
(933
)
 
(300
)
 
(1,486
)
 
(1,300
)
Interest expense
$
4,596

 
$
3,587

 
$
9,340

 
$
8,735

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):
 
2014
Deferred financing costs, January 1
$
5,237

Capitalization of deferred financing costs (1)
17,716

Less:
 
Amortization of deferred financing costs (2)
(3,596
)
Deferred financing costs, September 30
$
19,357

 
(1) See Note 7.
(2) This amount includes $2.3 million written off in connection with exiting the Previous Credit Facility and entering into the Senior Credit Facilities in August 2014.

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.
  

35

Future minimum annual demand payment receipts under these agreements as of September 30, 2014 were as follows: $1.1 million for the remainder of 2014; $5.6 million in 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 recognized 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 $1.5 million for the three and nine months ended September 30, 2014, respectively, and have been included within transportation, gathering and processing fees within Note 13. 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 13 were $0.2 million and $0.6 million for the three and nine months ended September 30, 2014, respectively.


36

Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
Overview
 
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 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, a Delaware limited liability company, 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”) 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 1, 2, 3, 7, 10, 11 and 14 to our condensed consolidated financial statements.
 
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 3,000 miles of pipelines. We are headquartered in Dallas, Texas.

Our Operations

Our integrated operations provide a full range of complementary services extending from wellhead to market, including gathering natural gas at the wellhead, treating natural gas to meet downstream pipeline and customer quality standards, processing natural gas to separate NGLs from natural gas, fractionating NGLs into the various components and selling or delivering pipeline quality natural gas, y-grade and purity product NGLs to various industrial and energy markets as well as large pipeline systems. Through our network of pipelines, we connect supplies of natural gas to our customers, which include industrial, commercial and power generation customers and local distribution companies. All of our operations are managed as and presented in one reportable segment.
Our results are determined primarily by the volumes of natural gas we gather and process, the efficiency of our processing plants and NGL fractionation plants, the commercial terms of our contractual arrangements, natural gas and NGL prices and our operations and maintenance expense. We manage our business with the goal to maximize the gross operating margin we earn from contracts balanced against any risks we assume in our contracts. Our contracts vary in duration from one month to several years and the pricing under our contracts varies depending upon several factors, including our competitive position, our acceptance of risks associated with longer-term contracts and our desire to recoup over the term of the contract any capital expenditures that we are required to incur to provide service to our customers. We purchase, gather, process, treat, compress, transport and sell natural gas and purchase, fractionate, transport and sell NGLs. Contracts with a counterparty generally contain one or more of the following arrangements:
•
Fixed-Fee.  We receive a fixed-fee per unit of natural gas volume that we gather at the wellhead, process, treat, compress and/or transport for our customers, or we receive a fixed-fee per unit of NGL volume that we fractionate. Some of our arrangements also provide for a fixed-fee for guaranteed transportation capacity on our systems.

37

•
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. 
We assess gross operating margin opportunities across our integrated value stream so that processing margins may be supplemented by gathering and transportation fees and opportunities to sell residue gas and NGLs at fixed-spreads. Gross operating margin earned under fixed-fee and fixed-spread arrangements is directly related to the volume of natural gas that flows through our systems and is generally independent from general commodity price levels. A sustained decline in commodity prices could result in a decline in volumes entering our system and, thus, a decrease in gross operating margin for our fixed-fee and fixed-spread arrangements.
The following table summarizes our gross operating margins from these arrangements (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
 
Gross Operating Margin
 
%
 
Gross Operating Margin
 
%
 
Gross Operating Margin
 
%
 
Gross Operating Margin
 
%
Fixed-fee
$
22,444

 
72.6
%
 
$
15,104

 
59.9
%
 
$
55,987

 
66.4
%
 
$
42,748

 
65.4
%
Fixed-spread
1,341

 
4.3
%
 
2,311

 
9.2
%
 
7,698

 
9.1
%
 
10,821

 
16.5
%
Sub-total
23,785

 
76.9
%
 
17,415

 
69.1
%
 
63,685

 
75.5
%
 
53,569

 
81.9
%
Commodity-sensitive
7,146

 
23.1
%
 
7,798

 
30.9
%
 
20,671

 
24.5
%
 
11,802

 
18.1
%
Total gross operating margin
$
30,931

 
100.0
%
 
$
25,213

 
100.0
%
 
$
84,356

 
100.0
%
 
$
65,371

 
100.0
%
 
How We Evaluate Our Operations
 
Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on at least a quarterly basis for consistency and trend analysis. These performance metrics include (a) volume, (b) gross operating margin, (c) operations and maintenance expense, (d) Adjusted EBITDA and (e) distributable cash flow.
 
Volume — We determine and analyze volumes by operating unit, but report overall volumes after elimination of intercompany deliveries. The volume of natural gas and NGLs on our systems depends on the level of production from natural gas wells connected to our systems and also from wells connected with other pipeline systems that are interconnected with our systems.
 
Gross Operating Margin — Gross operating margin of our contracts is one of the metrics we use to measure and evaluate our performance. Gross operating margin is not a measure calculated in accordance with accounting principles generally accepted in the United States of America (“GAAP”). We define gross operating margin as the sum of revenues less the cost of natural gas and NGLs sold. For our fixed-fee contracts, we record the fee as revenue and there is no offsetting cost of natural gas and NGLs sold. For our fixed-spread and commodity-sensitive arrangements, we record as revenue all of our proceeds from the sale of the natural gas and NGLs and record as an expense the associated cost of natural gas and NGLs sold.
 
Operations and Maintenance Expense — Our management seeks to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating and maintaining our assets. Direct labor costs,

38

insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operations and maintenance expense. These expenses are relatively stable and largely independent of volumes delivered through our systems, but may fluctuate depending on the activities performed during a specific period.
 
Adjusted EBITDA and Distributable Cash Flow — We believe that Adjusted EBITDA and distributable cash flow are widely accepted financial indicators of our operational performance and our ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA and distributable cash flow are not measures calculated in accordance with GAAP.

We define Adjusted EBITDA as net income/loss, plus interest expense, income tax expense, depreciation and amortization expense, equity in losses of joint venture investments, certain non-cash charges (such as non-cash unit-based compensation, impairments, loss on extinguishment of debt and unrealized losses on derivative contracts), major litigation costs net of recoveries, transaction-related costs, revenue deferral adjustment, loss on sale of assets and selected charges that are unusual or non-recurring; less interest income, income tax benefit, unrealized gains on derivative contracts, equity in earnings of joint venture investments and selected gains that are unusual or non-recurring. Adjusted EBITDA should not be considered an alternative to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP.
Adjusted EBITDA is used as a supplemental measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:
•
the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
•
the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions;
•
operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and
•
the attractiveness of capital projects and acquisitions and the overall rates of return on investment opportunities.
We define distributable cash flow as Adjusted EBITDA, plus interest income and income tax benefit, less cash paid for interest (net of capitalized costs), income tax expense and maintenance capital expenditures. We use distributable cash flow to analyze our performance and liquidity. Distributable cash flow does not reflect changes in working capital balances.
Distributable cash flow is used to assess:
•
the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders; and
•
the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.
 
Non-GAAP Financial Measures
 
Gross operating margin, Adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures provides useful information to investors in assessing our financial condition, results of operations and cash flows from operations. Net income is the GAAP measure most directly comparable to each of gross operating margin and Adjusted EBITDA. The GAAP measure most directly comparable to distributable cash flow is net cash provided by operating activities. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as an analytical tool because each excludes some but not all items that affect the most directly comparable GAAP financial measure. You should not consider any of gross operating margin, Adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross operating margin, Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
 
Reconciliations of Non-GAAP Financial Measures
 
The following table presents a reconciliation of gross operating margin to net loss (in thousands): 

39


Three Months Ended September 30,
 
Nine Months Ended September 30,

2014
 
2013
 
2014
 
2013
Reconciliation of gross operating margin to net loss
 
 
 
 
 
 
 
Gross operating margin
$
30,931

 
$
25,213

 
$
84,356

 
$
65,371

(Deduct):
 
 
 
 
 
 
 
Income tax expense
(69
)
 
(125
)
 
(133
)
 
(404
)
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
)
 
—

Loss on sale of assets, net of gains
(334
)
 
—

 
(292
)
 
—

General and administrative
(14,926
)
 
(5,227
)
 
(27,722
)
 
(16,850
)
Impairment of assets
(1,556
)
 
—

 
(1,556
)
 
—

Depreciation and amortization
(11,629
)
 
(9,447
)
 
(29,135
)
 
(24,958
)
Operations and maintenance
(16,889
)
 
(10,896
)
 
(39,494
)
 
(31,069
)
Net loss
$
(24,778
)
 
$
(4,069
)
 
$
(29,026
)
 
$
(16,645
)








































40



The following table presents reconciliations of net cash provided by operating activities to net loss, Adjusted EBITDA and distributable cash flow (in thousands): 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Reconciliation of Net Cash Flows Provided by Operating Activities to Net Loss and Adjusted EBITDA
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
$
(2,401
)
 
$
3,798

 
$
21,300

 
$
3,462

Add (deduct):


 


 


 


Depreciation and amortization
(11,629
)
 
(9,447
)
 
(29,135
)
 
(24,958
)
Unit-based compensation
(9,227
)
 
(552
)
 
(10,837
)
 
(1,645
)
Amortization and write-off of deferred financing costs
(2,921
)
 
(345
)
 
(3,596
)
 
(947
)
Loss on sale of assets, net of gains
(334
)
 
—

 
(292
)
 
—

Unrealized loss on financial instruments
(227
)
 
—

 
(539
)
 
—

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

 
(3,308
)
 
—

Impairment of assets
(1,556
)
 
—

 
(1,556
)
 
—

Other, net
(27
)
 
81

 
(81
)
 
63

Changes in operating assets and liabilities:


 


 


 


Trade accounts receivable, including affiliates
6,483

 
3,541

 
12,009

 
1,191

Prepaid expenses and other current assets
3,194

 
1,158

 
1,066

 
335

Other non-current assets
12

 
(8
)
 
32

 
60

Accounts payable and accrued expenses
2,064

 
378

 
(10,043
)
 
7,502

Other liabilities
(4,901
)
 
(2,673
)
 
(4,046
)
 
(1,708
)
Net loss
$
(24,778
)
 
$
(4,069
)
 
$
(29,026
)
 
$
(16,645
)
Add (deduct):


 


 


 


Depreciation and amortization
11,629

 
9,447

 
29,135

 
24,958

Interest expense
4,596

 
3,587

 
9,340

 
8,735

Loss on extinguishment of debt
2,316

 
—

 
2,316

 
—

Income tax expense
69

 
125

 
133

 
404

Unrealized loss on commodity swaps
207

 
—

 
338

 
—

Revenue deferral adjustment
444

 
—

 
2,070

 
—

Unit-based compensation
609

 
552

 
2,220

 
1,645

Loss on sale of assets, net of gains
334

 
—

 
292

 
—

Major litigation costs, net of recoveries
488

 
—

 
1,391

 
—

Transaction-related costs
10,506

 
—

 
10,813

 
—

Equity in losses of joint venture investments
3,308

 
—

 
3,308

 
—

Impairment of assets
1,556

 
—

 
1,556

 
—

Other, net
—

 
20

 
62

 
1,352

Adjusted EBITDA
$
11,284

 
$
9,662

 
$
33,948

 
$
20,449

(Deduct):


 


 


 


Cash interest, net of capitalized costs
(3,962
)
 
(3,231
)
 
(7,833
)
 
(7,756
)
Income tax expense
(69
)
 
(125
)
 
(133
)
 
(404
)
Maintenance capital expenditures
(1,309
)
 
(706
)
 
(4,047
)
 
(2,057
)
Distributable cash flow
$
5,944

 
$
5,600

 
$
21,935

 
$
10,232

 
Current Year Highlights
 
The following events took place during the nine months ended September 30, 2014 and have impacted, or are likely to impact, our financial condition and results of operations.
 
Public Equity Offering 

41

In February 2014, we completed a public equity offering of 9,200,000 additional common units and received a capital contribution from our General Partner to maintain its 2.0% interest in us. The net proceeds from the public offering of common units were $144.7 million. The net proceeds from the offering were used to fund the construction of our new pipeline extending into Webb County, Texas, were used to fund our Onyx acquisition in March 2014 and are being used for general partnership purposes. Pending use of the funds, we temporarily repaid borrowings under our Previous Credit Facility (as defined in Note 7 of our condensed consolidated financial statements), which we redrew to fund the construction of the new Webb County, Texas pipeline and for other general purposes.
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. See Note 2 to our condensed consolidated financial statements.

TexStar Rich Gas System Acquisition

On August 4, 2014, we acquired the TexStar Rich Gas System for $80 million in cash, the assumption of $100 million of debt (which was immediately repaid through our Term Loan Agreement (as defined below)) and our issuance of 14,633,000 of our Class B Convertible Units (see Note 2 to our condensed consolidated financial statements). The TexStar Rich Gas System consists of a 300 MMcf/d cryogenic processing plant, located in Bee County, Texas, and joint venture ownership in over 230 miles of rich 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. See Notes 1 and 2 to our condensed consolidated financial statements.

Senior Credit Facilities

On August 4, 2014, in connection with the consummation of the Holdings 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”). See Note 7 to our condensed consolidated financial statements.

Webb Pipeline Construction

During the first quarter of 2014, we began construction of an addition to our pipeline systems by approximately 90 miles into Webb County, Texas (the “Webb Pipeline”). During the nine months ended September 30, 2014, we incurred $63.8 million related to the Webb Pipeline which was reduced to approximately 45 miles in the third quarter of 2014 as a result of our ability to use a part of the TexStar Rich Gas System assets to connect the Webb Pipeline to the rest of our system.



42


Results of Operations
 
The following table summarizes our results of operations (in thousands, except operating data): 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
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
)
 
 
 
 
 
 
 
 
Other financial data:
 
 
 
 
 
 
 
Adjusted EBITDA
$
11,284

 
$
9,662

 
$
33,948

 
$
20,449

Gross operating margin
$
30,931

 
$
25,213

 
$
84,356

 
$
65,371

 
 
 
 
 
 
 
 
Maintenance capital expenditures
$
1,309

 
$
706

 
$
4,047

 
$
2,057

Growth capital expenditures
$
28,693

 
$
15,988

 
$
81,845

 
$
84,092

 
 
 
 
 
 
 
 
Operating data:
 
 
 
 
 
 
 
Average throughput volumes of natural gas (MMBtu/d) (1)
 
 
 
 
 
 
 
South Texas
684,067

 
379,878

 
626,575

 
377,816

Mississippi and Alabama
189,621

 
202,178

 
199,195

 
198,749

Total average throughput volumes of natural gas
873,688

 
582,056

 
825,770

 
576,565

Average volume of processed gas (MMBtu/d)
380,546

 
236,991

 
299,001

 
231,344

Average volume of NGLs fractionated (Bbls/d)
20,082

 
12,808

 
16,967

 
11,243

 
 
 
 
 
 
 
 
Realized prices on natural gas volumes ($/MMBtu)
$
4.10

 
$
3.67

 
$
4.60

 
$
3.80

Realized prices on NGL volumes ($/gal)
0.81

 
0.93

 
0.87

 
0.83

 
(1) Average throughput volumes of natural gas per day include sales, transportation, fuel and shrink volumes.


43

 
Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013

Volume and overview.  Our average throughput volume of natural gas per day increased 291,632 MMBtu/d, or 50%, to 873,688 MMBtu/d during the three months ended September 30, 2014, compared to 582,056 MMBtu/d during the three months ended September 30, 2013, due primarily to increased gas volumes in South Texas from the TexStar Rich Gas System acquired during the third quarter of 2014, increased gas volumes as a result of the pipelines acquired from Onyx in the first quarter of 2014, as well as increases in volume from new and existing customers in the Eagle Ford shale producing area.

Processed gas volumes increased 143,555 MMBtu/d, or 61%, to 380,546 MMBtu/d during the three months ended September 30, 2014, compared to 236,991 MMBtu/d during the three months ended September 30, 2013. This increase is due primarily to increased volumes from the TexStar Rich Gas System acquired during the third quarter of 2014 and from increases in volumes from new and existing customers in the Eagle Ford shale producing area.

NGLs fractionated for the three months ended September 30, 2014 were 20,082 Bbls/d, an increase of 7,274 Bbls/d, or 57%, compared to 12,808 Bbls/d for the three months ended September 30, 2013. This increase was due primarily to the impact of additional volumes of rich gas on our system and enhanced operational efficiency at our existing facilities during the three months ended September 30, 2014 compared to the three months ended September 30, 2013.
 
Gross operating margin for the three months ended September 30, 2014 was $30.9 million, compared to $25.2 million for the three months ended September 30, 2013. This increase of $5.7 million, or 23%, was due primarily to increased processed gas volumes on our system, including volumes from the TexStar Rich Gas System acquired during the third quarter of 2014 and the pipelines acquired from Onyx.
 
Adjusted EBITDA increased by $1.6 million, or 17%, to $11.3 million for the three months ended September 30, 2014, compared to $9.7 million for the three months ended September 30, 2013, due to higher volumes and margins from processing and fractionation activities partially offset by higher operating and general and administrative expenses. We had a net loss of $24.8 million for the three months ended September 30, 2014 compared to a net loss of $4.1 million for the three months ended September 30, 2013. Net loss increased due to higher overall expenses, including transaction-related costs affiliated with the Holdings Transaction and the TexStar Rich Gas System Transaction, and equity in losses of our joint venture investments, partially offset by higher gross margin.
 
Revenues.  Our total revenues for the three months ended September 30, 2014 were $211.5 million, compared to $160.6 million for the three months ended September 30, 2013. This increase of $50.9 million, or 32%, was due primarily to revenue from sales of natural gas increasing by $24.4 million, from higher fee income and from an increase in realized prices in natural gas. Additionally, revenue increased from sales of NGLs and condensate by $19.1 million for the three months ended September 30, 2014 compared to the three months ended September 30, 2013. The increase was due to higher NGL volumes produced in our facilities.  
 
Cost of natural gas and NGLs sold.  Our cost of natural gas and NGLs sold for the three months ended September 30, 2014 was $180.6 million, compared to $135.4 million for the three months ended September 30, 2013. This increase of $45.1 million, or 33%, was due primarily to increased natural gas volumes purchased, increased NGL volumes purchased and higher natural gas prices compared to the same period in 2013.
 
Operations and maintenance expenses.  Operations and maintenance expenses for the three months ended September 30, 2014 were $16.9 million, compared to $10.9 million for the three months ended September 30, 2013. This increase of $6.0 million, or 55%, was due primarily to $2.0 million from accelerated vesting of our long-term incentive plan (“LTIP”) awards, higher operating costs of $1.9 million due to the acquisition of additional assets and increased labor and benefits costs of $0.6 million from employee additions during the three months ended September 30, 2014 compared to the three months ended September 30, 2013.
 
General and administrative expenses.  General and administrative expenses for the three months ended September 30, 2014 were $14.9 million, compared to $5.2 million for the three months ended September 30, 2013. This increase of $9.7 million, or 186%, was due primarily to $6.6 million from the accelerated vesting of LTIP awards, as a result of the change of control in August 2014, higher professional fees of $2.3 million, mostly related to the TexStar Rich Gas System Transaction, and increased labor and benefits costs of $0.5 million from employee additions for the three months ended September 30, 2014 compared to the three months ended September 30, 2013.
 

44

Depreciation and amortization expense.  Depreciation and amortization expense for the three months ended September 30, 2014 was $11.6 million, compared to $9.4 million for the three months ended September 30, 2013. The increase of $2.2 million, or 23%, was due primarily to depreciation of the TexStar Rich Gas System assets and other capital projects placed in service during and after the three months ended September 30, 2013.
 
Equity in losses of joint venture investments.  Our share of losses incurred by the joint venture investments was $3.3 million for the period from August 4, 2014 through September 30, 2014. The related joint venture agreements require us to pay for the joint ventures’ operating costs, excluding depreciation and amortization. As a result, our share of the joint ventures’ losses are primarily related to the joint ventures’ depreciation and amortization.

Interest expense.  For the three months ended September 30, 2014, interest expense was $4.6 million, compared to $3.6 million for the three months ended September 30, 2013. This increase of $1.0 million, or 28%, was due to higher average borrowings related to the Senior Credit Facilities entered into in August 2014.

Loss on extinguishment of debt.  In the third quarter of 2014, we incurred a loss on the extinguishment of debt of $2.3 million in connection with the write-off of deferred financing costs related to exiting the Previous Credit Facility and entering into the Senior Credit Facilities in August 2014.

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

Volume and overview.  Our average throughput volume of natural gas per day increased 249,205 MMBtu/d, or 43%, to 825,770 MMBtu/d during the nine months ended September 30, 2014, compared to 576,565 MMBtu/d during the nine months ended September 30, 2013, due primarily to increased gas volumes in South Texas from the TexStar Rich Gas System acquired in the third quarter of 2014, increased gas volumes as a result of the pipelines acquired from Onyx in the first quarter of 2014 as well as increases in volume from new and existing customers in the Eagle Ford shale producing area.

Processed gas volumes increased 67,657 MMBtu/d, or 29%, to 299,001 MMBtu/d during the nine months ended September 30, 2014, compared to 231,344 MMBtu/d during the nine months ended September 30, 2013. This increase is due primarily to increased volumes from the TexStar Rich Gas System acquired in the third quarter of 2014 and from increases in volumes from new and existing customers in the Eagle Ford shale producing area.

NGLs fractionated for the nine months ended September 30, 2014 was 16,967 Bbls/d, an increase of 5,724 Bbls/d, or 51%, compared to 11,243 Bbls/d for the nine months ended September 30, 2013. This increase was due primarily to the impact of additional volumes of rich gas on our system and enhanced operational efficiency at our facilities during the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013.
 
Gross operating margin for the nine months ended September 30, 2014 was $84.4 million, compared to $65.4 million for the nine months ended September 30, 2013. This increase of $19.0 million, or 29%, was due primarily to increased processed gas volumes on our system, including volumes from the TexStar Rich Gas System acquired in the third quarter of 2014 and the pipelines acquired from Onyx in the first quarter of 2014, as well as increased transportation, gathering and processing fees.
 
Adjusted EBITDA increased by $13.5 million, or 66%, to $33.9 million for the nine months ended September 30, 2014, compared to $20.4 million for the nine months ended September 30, 2013, due to higher volumes and margins from processing and fractionation activities partially offset by higher operating and general and administrative expenses. We had a net loss of $29.0 million for the nine months ended September 30, 2014 compared to a net loss of $16.6 million for the nine months ended September 30, 2013. Net loss increased due to higher overall expenses, including transaction-related costs affiliated with the Holdings Transaction and the TexStar Rich Gas System Transaction, and equity in losses of our joint venture investments, partially offset by higher gross margin.
 
Revenues.  Our total revenues for the nine months ended September 30, 2014 were $620.1 million, compared to $459.6 million for the nine months ended September 30, 2013. This increase of $160.6 million, or 35%, was due primarily to revenue from sales of natural gas increasing by $88.3 million and an increase in realized prices in natural gas. Additionally, revenue increased from sales of NGLs and condensate by $59.1 million for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013. The increase was due to higher NGL volumes produced in our facilities.
 
Cost of natural gas and NGLs sold.  Our cost of natural gas and NGLs sold for the nine months ended September 30, 2014 was $535.8 million, compared to $394.2 million for the nine months ended September 30, 2013. This increase of $141.6 million, or 36%, was due primarily to increased natural gas volumes purchased, increased NGL volumes purchased and higher natural gas prices compared to the same period in 2013.

45

 
Operations and maintenance expenses.  Operations and maintenance expenses for the nine months ended September 30, 2014 were $39.5 million, compared to $31.1 million for the nine months ended September 30, 2013. This increase of $8.4 million, or 27%, was due primarily to increased labor and benefits costs of $2.0 million from the accelerated vesting of our LTIP awards, $1.9 million from employee additions, higher operating costs of $1.2 million due to the acquisition of additional assets and higher utility costs of $1.0 million during the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013.
 
General and administrative expenses.  General and administrative expenses for the nine months ended September 30, 2014 were $27.7 million, compared to $16.9 million for the nine months ended September 30, 2013. This increase of $10.9 million, or 65%, was due primarily to increased expenses related to labor and benefits costs of $6.6 million from the accelerated vesting of LTIP awards, as a result of the change of control in August 2014, and $1.7 million from employee additions, together with higher professional fees of $1.8 million, mostly related to the TexStar Rich Gas System Transaction, for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013.
 
Depreciation and amortization expense.  Depreciation and amortization expense for the nine months ended September 30, 2014 was $29.1 million, compared to $25.0 million for the nine months ended September 30, 2013. The increase of $4.1 million, or 17%, was due primarily to depreciation of the TexStar Rich Gas System assets acquired in the third quarter of 2014 and other capital projects placed in service during and after the nine months ended September 30, 2013.

Equity in losses of joint venture investments.  Our share of losses incurred by the joint venture investments was $3.3 million for the period from August 4, 2014 through September 30, 2014. The related joint venture agreements require us to pay for the joint ventures’ operating costs, excluding depreciation and amortization. As a result, our share of the joint ventures’ losses are primarily related to the joint ventures’ depreciation and amortization.
 
Interest expense.  For the nine months ended September 30, 2014, interest expense was $9.3 million, compared to $8.7 million for the nine months ended September 30, 2013. This increase of $0.6 million was due to higher average borrowings.

Loss on extinguishment of debt.  In the third quarter of 2014, we incurred a loss on the extinguishment of debt of $2.3 million in connection with the write-off of deferred financing costs related to exiting the Previous Credit Facility and entering into the Senior Credit Facilities in August 2014.
 
Liquidity and Capital Resources
 
Sources of Liquidity
 
Our primary sources of liquidity are cash generated from operations, cash raised through issuances of additional equity and debt securities and borrowings under our credit facilities. Our primary cash requirements consist of operating and maintenance and general and administrative expenses, growth and maintenance capital expenditures to sustain existing operations or generate additional revenues, interest payments on outstanding debt, purchases and construction of new assets, business acquisitions and distributions to unitholders.
We expect to fund short term cash requirements, such as operating and maintenance and general and administrative expenses and maintenance capital expenditures, primarily through operating cash flows. We expect to fund long-term cash requirements, such as for expansion projects and acquisitions, through several sources, including operating cash flows, borrowings under our Senior Credit Facilities and issuances of additional debt and equity securities, as appropriate and subject to market conditions. See Note 7 to our condensed consolidated financial statements.
As of October 30, 2014, we had $448.9 million in outstanding borrowings under our Senior Credit Facilities. Under our Third A&R Revolving Credit Agreement, we have the ability to borrow up to $200 million under our five-year revolving credit facility (the “Credit Facility”) less any letters of credit amounts outstanding which as of October 30, 2014 provided us access to $154.3 million.
Capital expenditures.  Our business is capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of and will continue to include:
•
growth capital expenditures, which are capital expenditures to expand or increase the efficiency of the existing operating capacity of our assets. Growth capital expenditures include expenditures that facilitate an increase in volumes within our operations, but exclude expenditures for acquisitions; and

46

•
maintenance capital expenditures, which are capital expenditures that are not considered growth capital expenditures.
 
The following table summarizes our capital expenditures (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Maintenance capital
$
1,309

 
$
706

 
$
4,047

 
$
2,057

Growth capital
28,693

 
15,988

 
81,845

 
84,092

Capital expenditures
$
30,002

 
$
16,694

 
$
85,892

 
$
86,149


Our growth capital expenditures during the nine months ended September 30, 2014 related primarily to construction of the Webb Pipeline. The growth capital expenditures during the nine months ended September 30, 2013 primarily related to our Bonnie View NGL fractionation facility completed in February 2013 and our Bee Line pipeline completed in February 2013.
 
Outlook.  Cash flow is affected by a number of factors, some of which we cannot control. These factors include prices and demand for our services, operational risks, volatility in commodity prices or interest rates, industry and economic conditions, conditions in the financial markets and other factors.
 
Our ability to benefit from growth projects to accommodate strong drilling activity and the associated need for infrastructure assets and services is subject to operational risks and uncertainties such as the uncertainty inherent in some of the assumptions underlying design specifications for new, modified or expanded facilities. These risks also impact third party service providers and their facilities. Delays or under-performance of our facilities or third party facilities may adversely affect our ability to generate cash from operations and comply with our obligations, including the covenants under our debt instruments. In other cases, actual production delivered may fall below volume estimates that we relied upon in deciding to pursue an acquisition or other growth project. Future cash flow and our ability to comply with our debt covenants would likewise be affected adversely if we experienced declining volumes over a sustained period and/or unfavorable commodity prices.
 
We believe that cash from operations, cash on hand and our unused borrowings under our Senior Credit Facilities will provide liquidity to meet future short term capital requirements and to fund committed capital expenditures for a reasonable period of time. The sufficiency of these liquidity sources to fund necessary and committed capital needs will be dependent upon our ability to meet our covenant requirements of our Senior Credit Facilities. We believe we have and will continue to have sufficient liquidity to operate our business. See Note 7 to our condensed consolidated financial statements.
Growth projects and acquisitions are key elements of our business strategy. We intend to finance our growth capital primarily through the issuance of debt and equity. The timing, size or success of any acquisition or expansion effort and the associated potential capital commitments are unpredictable. To consummate acquisitions or capital projects, we may require access to additional capital. Our access to capital over the longer term will depend on our future operating performance, financial condition and credit rating and, more broadly, on the availability of equity and debt financing, which will be affected by prevailing conditions in our industry, the economy and the financial markets and other financial and business factors, many of which are beyond our control.
Cash Flows
 
The following table provides a summary of our cash flows by category (in thousands): 
 
Nine Months Ended September 30,
 
2014
 
2013
Net cash provided by operating activities
$
21,300

 
$
3,462

Net cash used in investing activities
(203,626
)
 
(88,820
)
Net cash provided by financing activities
180,800

 
78,654

 
Operating cash flows — Net cash provided by operating activities was $21.3 million for the nine months ended September 30, 2014, compared to $3.5 million net cash provided by operating activities for the nine months ended September 30, 2013. The increase in cash from operating activities was primarily the result of increased gross margin during the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013. In addition, the net changes in accounts receivable and accounts payable and accrued liabilities of $6.7 million caused an increase in operating cash flows for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013.


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Investing cash flows — Net cash used in investing activities for the nine months ended September 30, 2014 was $203.6 million, compared to $88.8 million for the nine months ended September 30, 2013. The increase of $114.8 million primarily relates to the TexStar Rich Gas System Transaction in August 2014 and the Onyx acquisition in March 2014.  
 
Financing cash flows — Net cash provided by financing activities for the nine months ended September 30, 2014 was $180.8 million, compared to $78.7 million for the nine months ended September 30, 2013. The increase was due to proceeds received from our $144.7 million equity offering, net of expenses, in the first quarter of 2014, as well as additional net borrowings of $123.1 million from our debt instruments. The increase in cash provided by financing activities was partially offset by $100 million of debt assumed and immediately repaid by us in connection with the TexStar Rich Gas System Transaction, increased distributions paid of $16.8 million and additional financing costs of $15.6 million associated with the Senior Credit Facilities.
 
Off-Balance Sheet Arrangements
 
We have no off-balance sheet arrangements, except for our letters of credit under our Credit Facility described in Note 7 to our condensed consolidated financial statements.
 
Recent Accounting Pronouncements
 
For information on new accounting pronouncements, see Note 1 to our condensed consolidated financial statements.
 
Critical Accounting Policies and Estimates
 
Our critical accounting policies are described in our 2013 Annual Report on Form 10-K.  The preparation of financial statements in conformity with GAAP requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no significant changes to our critical accounting policies as described in our 2013 Annual Report on Form 10-K.
 
Item 3. Quantitative and Qualitative Disclosures about Market Risk.
 
There have been no significant changes to our quantitative and qualitative disclosures about market risk as described in our 2013 Annual Report on Form 10-K.
 
Item 4.  Controls and Procedures.
 
Disclosure controls and procedures.  The Chief Executive Officer and Chief Financial Officer of our General Partner, who have responsibility for our management, have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)), as of the end of the period covered by this report (the “Evaluation Date”). Based on such evaluation, the Chief Executive Officer and Chief Financial Officer of our General Partner have concluded that, as of the Evaluation Date, our disclosure controls and procedures are effective.
 
Internal control over financial reporting.  There have been no changes in internal controls over financial reporting (as defined in Rule 13a—15(f) or Rule 15d—15(f) of the Exchange Act) during the third quarter of 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 
PART II — OTHER INFORMATION
 
Item 1.  Legal Proceedings.
 
A description of our material legal proceedings is included in Note 8 to our condensed consolidated financial statements, “Commitments and Contingencies – Legal Matters” of this report, and is incorporated herein by reference.

Item 1A. Risk Factors.
 
The risk factors contained in our 2013 Annual Report on Form 10-K under Part 1A “Risk Factors” and in the “Update to Risk Factors” section of our Quarterly Report 10-Q for the quarterly period ended June 30, 2014, are incorporated herein by reference.
 

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These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, results of operations and financial condition and our ability to make distributions.
 
Item 2. Unregistered Sales of Securities.
 
On August 4, 2014, we issued 14,633,000 Class B Convertible Units to TexStar as part of the consideration given for the TexStar Rich Gas System. The Class B Convertible Units were issued and sold pursuant to the definitive agreements in respect of the TexStar Rich Gas System Transaction in a transaction exempt from registration under section 4(a)(2) of the Securities Act of 1933, as amended, and the rules and regulations promulgated thereunder. See Notes 2 and 10 to our condensed consolidated financial statements.

Item 5. Other Information.
 
On November 6, 2014, the General Partner entered into a Retention Agreement with J. Michael Anderson, the Senior Vice President and Chief Financial Officer of the General Partner (the “Retention Agreement”). The Retention Agreement provides for an incentive payment of $325,000 to Mr. Anderson if, among other conditions, Mr. Anderson remains employed with the General Partner through May 1, 2015.

The foregoing description of the Retention Agreement is not complete and is qualified in its entirety by reference to the full text of the Retention Agreement, which is attached as Exhibit 10.4 to this report and incorporated herein by reference.
Item 6. Exhibits.
 
The information set forth in the Index to Exhibits accompanying this report is incorporated into this Item 6 by reference.


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SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
 
SOUTHCROSS ENERGY PARTNERS, L.P.
 
 
 
 
 
 
By:
Southcross Energy Partners GP, LLC, its general partner
 
 
 
 
 
 
 
 
Date:
November 7, 2014
By:
/s/ J. Michael Anderson
 
 
 
J. Michael Anderson
 
 
 
Senior Vice President and Chief Financial Officer
 
 
 
Principal Financial Officer
 
 
 
 
Date:
November 7, 2014
By:
/s/ Donna A. Henderson
 
 
 
Donna A. Henderson
 
 
 
Vice President and Chief Accounting Officer
 
 
 
Principal Accounting Officer

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INDEX TO EXHIBITS
Exhibit
 
 
Number
 
Description
3.1
 
Certificate of Limited Partnership of Southcross Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).
3.2
 
Third Amended and Restated Agreement of Limited Partnership of Southcross Energy Partners, L.P., dated as of August 4, 2014 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated August 4, 2014).
3.4
 
Certificate of Formation of Southcross Energy Partners GP, LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).
3.5
 
Second Amended and Restated Limited Liability Company Agreement of Southcross Energy Partners GP, LLC, dated as of August 4, 2014 (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K dated August 4, 2014).
4.1
 
Registration Rights Agreement, dated as of April 12, 2013, by and between Southcross Energy Partners, L.P. and Southcross Energy LLC (incorporated by reference to Exhibit 4.1 to our Annual Report on Form 10-K dated April 15, 2013).
10.1
 
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 the lenders party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated August 4, 2014).
10.2
 
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 the lenders party thereto (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K dated August 4, 2014).
10.3
 
Southcross Energy Partners GP, LLC and Southcross GP Management Holdings, LLC 2014 Equity Incentive Plan and Form of Unit Award Agreement (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K dated August 4, 2014).
10.4*
 
Retention Agreement, dated November 6, 2014, between Southcross Energy Partners GP, LLC and J. Michael Anderson.
31.1*
 
Certification of Chief Executive Officer required by Rule 13a-14(a)/15d-14(a).
31.2*
 
Certification of Chief Financial Officer required by Rule 13a-14(a)/15d-14(a).
32.1*†
 
Certifications of Chief Executive Officer and Chief Financial Officer required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
101.INS*†
 
XBRL Instance Document.
101.SCH*†
 
XBRL Taxonomy Extension Schema.
101.CAL*†
 
XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*†
 
XBRL Taxonomy Extension Definition Linkbase.
101.LAB*†
 
XBRL Taxonomy Extension Label Linkbase.
101.PRE*†
 
XBRL Extension Presentation Linkbase.
 

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

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